Clean Fuel Regulations: SOR/2022-140

Canada Gazette, Part II, Volume 156, Number 14

Registration
SOR/2022-140 June 21, 2022

CANADIAN ENVIRONMENTAL PROTECTION ACT, 1999
ENVIRONMENTAL VIOLATIONS ADMINISTRATIVE MONETARY PENALTIES ACT

P.C. 2022-704 June 20, 2022

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 December 19, 2020, a copy of the proposed Clean Fuel Regulations, substantially in the annexed form, 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 the Governor in Council is of the opinion that the proposed Regulations could make a significant contribution to the prevention of, or a reduction in, air pollution resulting, directly or indirectly, from the combustion of liquid fossil fuels;

And whereas, under subsection 140(4) of that Act, before recommending the proposed Regulations, the Minister of the Environment offered to consult with the governments of the provinces and the members of the National Advisory Committee who are representatives of Aboriginal governments;

Therefore, Her Excellency the Governor General in Council, on the recommendation of the Minister of the Environment, makes the annexed Clean Fuel Regulations under sections 140^{footnote c} and 326 and subsection 330(2) of the Canadian Environmental Protection Act, 1999 b and subsection 5(1) of the Environmental Violations Administrative Monetary Penalties Act ^{footnote d}.

TABLE OF PROVISIONS

Clean Fuel Regulations

Interpretation

1 Definitions

2 Incorporation by reference

3 Standard conditions

Application

4 Exemption — primary suppliers

Requirements for Liquid Fuels

Carbon-Intensity Limits

5 Requirement — carbon intensity

6 Volumetric requirement — gasoline

7 Volumetric requirement — diesel

8 Pool of liquid fuel — volume

Reduction Requirement

9 Reduction in tonnes

Registration as Primary Supplier

10 Registration report

Compliance Credits

Use

11 Satisfaction of reduction requirement

12 Deemed compliance — gasoline

13 July 31 — gasoline

14 December 15 — gasoline

15 Limits on credit use — funding program

16 Deferral of reduction requirements

17 Increase to deferred portion

18 Reduction — July 31

Creation

Reduction of CO₂e Emissions

19 Liquid class

20 Gaseous class

21 Agreement to create credits

22 Submission to Minister

Creation of Provisional Compliance Credits

23 Creation of provisional compliance credits

24 Deposit into account

Registration as Registered Creator

25 Registration report

26 Change of information

27 Cancellation of registration

Compliance-Credit Accounts

28 Opening

29 Credit remains in account

CO₂e-Emission-Reduction Project

30 Series of activities

31 Generic quantification method

32 Specific quantification method

33 Exception

34 Application for recognition

35 Recognition — generic quantification method

36 Recognition — specific quantification method

37 Application for recognition — change of method

38 Application for recognition — project in foreign country

39 Recognition — project in foreign country

40 Application for recognition — change of method

41 Number of compliance credits — projects in foreign country

42 Extension of period — five years

43 Federal or provincial laws

44 Failure to comply with record requirements

Displacement of Fossil Fuel Usage

Land-Use and Biodiversity Criteria for Low-Carbon-Intensity Fuels

45 Maximum quantity

46 Eligibility requirements

47 Quantity of eligible feedstock

48 Wildlife habitat

49 Damaging agents

50 Crops — indirect changes to land use

51 Crops — excluded land

52 Forest-based feedstock

53 Exemption — approval by EPA

54 Exemption — no net expansion

55 Exemption — other laws

56 Low-carbon-intensity fuel

57 Producer or importer — paragraph 46(1)(a)

58 Declaration by harvester

59 Producer records

60 Non-application

61 Certification

62 Approval by Minister

63 Eligibility conditions for accreditation

64 No outsource

65 Consecutive certifications

66 Certification team — members

67 Applicable standards for certification

68 Annual surveillance audit

69 Site visits

70 Unambiguous identification

71 Denial or revocation

72 Denial or suspension of certification

73 Other circumstances of non-conformity

74 Prior certification under another certification scheme

Determination of Carbon Intensity

75 Low-carbon-intensity fuel

76 Fuel LCA Model — registered creator or foreign supplier

77 Fuel LCA Model — co-processed low-carbon-intensity fuel

78 Compressed and liquefied gases

79 Electricity

80 Application for approval of carbon intensity

81 Pathway approval

82 Information to be provided

83 Information to be provided — section 78

84 Information to be provided — section 79

85 Approval

86 End of validity

87 New application

88 Adjustment of credits

89 Adjustment — actual carbon intensity

90 Adjustment after June 30, 2024

91 Application for temporary approval

92 Registration of foreign supplier

93 Registration — carbon-intensity contributor

Low-Carbon-Intensity Fuels

94 Liquid class

95 Gaseous class

96 Biogas used to produce electricity

97 Multiple feedstocks

Fuel or Other Energy Source for Vehicles

98 Gas for vehicles

99 Renewable gaseous fuel

100 Creator — producer or importer

101 Electricity — charging-site host

102 Electricity – charging-network operator

103 Use of revenue — electric vehicles

104 Hydrogen

Compliance-Credit Transfer System

General

105 Participating registered creator

106 Eligibility to transfer credits

107 Fair market value

Transfer of Compliance Credits

108 Transfer on creation

109 Immediate transfer

Compliance-Credit Clearance Mechanism

110 Pledging credits to mechanism

111 No clearance mechanism

112 Transfer through clearance mechanism

Registered Emission-Reduction Funding Program

113 Registration

114 Application for registration

115 Registration — conditions

116 Cancelling registration

117 List of programs

118 Contribution to funding program

119 No subsequent transfer

Reporting

120 Annual credit-creation report

121 Quarterly credit-creation reports

122 Credit-adjustment report

123 Carbon-intensity-pathway report

124 Material balance report

125 Compliance-credit revenue report

126 Compliance-credit balance report

127 Compliance report

128 Complementary compliance report

Verification

Obligation to Verify

129 Condition of eligibility — reports and applications

130 Verification of applications

131 Verification of reports

132 Declarations

133 Contents of verification report

134 Management system and processes

135 Submission of all reports

136 Monitoring plan

Requirements Respecting Verification Bodies

137 Accredited body

138 Eligibility conditions for accreditation

139 Independent reviewer

140 Technical accreditation

141 Team leader

142 Subcontract — conditions

143 Outsourcing of verification — conditions

144 Other verification report

145 Conflicts of interest

146 No work without decision by Minister

147 Five consecutive verifications

Applicable Standards

148 Verification of application and report

149 Criteria

150 Materiality quantitative threshold

151 Material qualitative misstatements

152 Site visits

153 Aggregate quantitative misstatements

154 Opinion

Excess Compliance Credits

155 Export — request for cancellation and report

156 Re-submission of report

157 Notice of error

158 Suspension of excess compliance credits

159 Lifting of suspension

160 Cancellation of excess credits

Measurement, Electronic Reporting and Records

Measurement

161 Requirements

162 Biogas energy density

163 Rounding

Electronic Reporting

164 Electronic submission — report or notice

Recording and Retention of Information

165 When records are made

166 Retention of information

167 Records related to compliance units

168 Information requested by Minister

Transitional Provisions

169 Gasoline compliance units

170 Distillate compliance units

171 Request for deposit of credits

Consequential Amendments

172 Renewable Fuels Regulations

173 Environmental Violations Administrative Monetary Penalties Regulations

Repeal

175 Repeal

Coming into Force

176 Registration

SCHEDULE 1

SCHEDULE 2

SCHEDULE 3

SCHEDULE 4

SCHEDULE 5

SCHEDULE 6

SCHEDULE 7

SCHEDULE 8

SCHEDULE 9

SCHEDULE 10

SCHEDULE 11

SCHEDULE 12

SCHEDULE 13

SCHEDULE 14

SCHEDULE 15

SCHEDULE 16

SCHEDULE 17

SCHEDULE 18

SCHEDULE 19

SCHEDULE 20

SCHEDULE 21

Clean Fuel Regulations

Interpretation

Definitions

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

account holder,

with respect to any account opened under section 28, means the primary supplier or registered creator for whom the Minister opened the account. (titulaire)

Act

means the Canadian Environmental Protection Act, 1999. (Loi)

authorized agent

means,

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

baseline carbon intensity

means the weighted average carbon intensity of the gasoline or diesel used in Canada for the year 2016, as set out in subsection 5(3). (intensité en carbone de base)

biogas

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

biomass

means the biodegradable fraction of products, waste and residues of a biological origin — including plant and animal substances — originating from agriculture, forestry and other industries, such as fishing and aquaculture, as well as the fraction of waste, including industrial and municipal waste, of a biological origin. (biomasse)

carbon intensity,

in relation to a fuel, energy source, or material input that is renewable natural gas, biogas, renewable propane or hydrogen, means the quantity in grams of CO₂e per megajoule of energy contained in that fuel, energy source or material input that is released over the life cycle of that fuel, energy source or material input, including during the activities carried out during the stages of the life cycle, such as

(a) the extraction or production of the feedstock used to produce the fuel, energy source or material input;
(b) the processing, refining or upgrading of the feedstock to produce the fuel, energy source or material input;
(c) the transportation or distribution of the feedstock, of intermediary products or of the fuel, energy source or material input; and
(d) the combustion of the fuel. (intensité en carbone)

carbon-intensity contributor

means a person who applies for the approval of a carbon intensity under subsection 80(1) for a set of activities carried out over the life cycle of a fuel in the liquid class or a low-carbon-intensity fuel with the intention to transfer the approved carbon intensity to a registered creator or foreign supplier or to another carbon-intensity contributor. (contributeur à l’intensité en carbone)

charging-network operator

means a person who operates a communication platform that collects data on the electricity supplied by a charging station and who is the owner of that data. (exploitant d’un réseau de recharge)

charging-site host

means a person who owns or leases a charging station and who has the legal right to have the charging station installed. (hôte d’une station de recharge)

charging station

means a device that is used in Canada to charge the battery on board an electric vehicle by supplying electricity to the electric vehicle and that is capable of communicating with a server, whether through the Internet or using a cellular signal or connected vehicle communications, to report the quantity of electricity supplied and the time at which it is supplied. (borne de recharge)

CO₂e

means the quantity of carbon dioxide, expressed in grams or tonnes, that would be required to produce a warming effect equivalent to another greenhouse gas over a particular period of time, as set out in the Fuel LCA Model. (CO₂e)

compliance-credit transfer system

means the system administered by the Minister for the transfer of credits in accordance with sections 105 to 112. (mécanisme de cession des unités de conformité)

compliance period

means

(a) the period that begins on the day on which these Regulations are registered and ends on December 31, 2022;
(b) the period that begins on January 1, 2023 and ends on June 30, 2023;
(c) the period that begins on July 1, 2023 and ends on December 31, 2023; or
(d) after December 31, 2023, each calendar year. (période de conformité)

co-processed low-carbon-intensity fuel

means the portion of a fuel that is produced from a mixture of a petroleum feedstock and a non-petroleum feedstock that are used simultaneously in the same processing unit of a petroleum refinery or upgrader facility and that is a low-carbon-intensity fuel derived from a non-petroleum feedstock. (combustible cotraité à faible intensité en carbone)

co-processed low-carbon-intensity propane

means a co-processed low-carbon-intensity fuel that is a mixture that is gaseous at standard conditions and consists primarily of propane. (propane cotraité à faible intensité en carbone)

crop

includes a woody biomass crop with a rotational period that is not more than 25 years. (culture)

deferred portion of the reduction requirements,

with respect to a compliance period, means the portion of the sum of the reduction requirements in respect of gasoline and diesel for that compliance period that has been deferred by a primary supplier in accordance with section 16, as increased in accordance with section 17 and as reduced in accordance with section 18. (partie reportée des exigences de réduction)

diesel

means liquid petroleum fuel that

(a) is sold or represented as diesel or as a fuel suitable for use in a diesel engine; or
(b) evaporates at atmospheric pressure, has a boiling point between 130°C and 400°C and is suitable for use in a diesel engine. (diesel)

diesel replacement

means a liquid low-carbon-intensity fuel that is suitable for use in a diesel engine, furnace or open flame burner or that is used in aviation. (substitut du diesel)

electric vehicle

means a vehicle that is propelled by an electric motor whose source of electricity is a rechargeable battery that is charged from a source of electricity that is not on board the vehicle. It includes a plug-in hybrid electric vehicle. (véhicule électrique)

eligible feedstock

means a feedstock that is eligible under section 46 and meets the requirements set out in sections 48 to 52, except if it is exempted under any of sections 53 to 55, as well as the requirements set out in section 57. (charge d’alimentation admissible)

EPA

means the United States Environmental Protection Agency. (EPA)

foreign supplier

means the owner of a facility outside Canada at which a low-carbon-intensity fuel is produced or the person who leases, operates, controls or manages such a facility. (fournisseur étranger)

Fuel LCA Model

means the fuel life-cycle assessment model that is developed by the Minister in accordance with ISO Standard 14040 and that consists of the procedures that must be followed to determine the carbon intensity of a fuel, energy source or material input using life-cycle inventories for various pathways. (modèle ACV des combustibles)

fuelling station

means a facility in Canada at which vehicles are supplied with fuel or with hydrogen used as an energy source and includes a mobile facility. (station de ravitaillement)

gaseous class

means a class of fuel consisting of propane and natural gas. (catégorie des combustibles gazeux)

gasoline

means liquid petroleum fuel that

(a) is sold or represented as gasoline, as a fuel suitable for use in a spark-ignition engine or as a fuel requiring only the addition of a low-carbon-intensity fuel or an oxygenate to make it suitable for use in a spark-ignition engine; or
(b) is suitable for use in a spark-ignition engine and has, as determined by the applicable test method listed in National Standard of Canada CAN/CGSB-3.5-2021, entitled Automotive Gasoline, the following characteristics:
- (i) a vapour pressure of no less than 38 kPa,
- (ii) an anti-knock index of no less than 80,
- (iii) a distillation temperature at which 10% of the fuel has evaporated of no less than 35°C and no more than 70°C, and
- (iv) a distillation temperature at which 50% of the fuel has evaporated of no less than 65°C and no more than 120°C. (essence)

gasoline replacement

means a liquid low-carbon-intensity fuel that is suitable for use in a spark-ignition engine. (substitut de l’essence)

GPS

means global positioning system. (GPS)

hydrogen fuel cell vehicle

means a vehicle propelled solely by an electric motor that uses electricity produced by an electrochemical cell from hydrogen. (véhicule à pile à hydrogène)

ISO/IEC Standard 17011

means International Standard ISO/IEC 17011, entitled Conformity assessment — Requirements for accreditation bodies accrediting conformity assessment bodies, published by the International Organization for Standardization. (norme ISO/IEC 17011)

ISO/IEC Standard 17021-1

means the International Standard ISO/IEC 17021-1, entitled Conformity assessment — Requirements for bodies providing audit and certification of management systems — Part 1: Requirements, published by the International Organization for Standardization (norme ISO/IEC 17021-1)

ISO/IEC Standard 17065

means the International Standard ISO/IEC 17065, entitled Conformity assessment — Requirements for bodies certifying products, processes and services, published by the International Organization for Standardization. (norme ISO/IEC 17065)

ISO Standard 14040

means the International Standard ISO 14040, entitled Environmental management — Life cycle assessment — Principles and framework, published by the International Organization for Standardization. (norme ISO 14040)

ISO Standard 14044

means the International Standard ISO 14044, entitled Environmental management — Life cycle assessment — Requirements and guidelines, published by the International Organization for Standardization. (norme ISO 14044)

ISO Standard 14064-2

means the International Standard ISO 14064-2, entitled Greenhouse gases — Part 2: Specification with guidance at the project level for quantification, monitoring and reporting of greenhouse gas emission reductions or removal enhancements, published by the International Organization for Standardization. (norme ISO 14064-2)

ISO Standard 14064-3:2019

means the International Standard ISO 14064-3:2019, entitled Greenhouse gases — Part 3: Specification with guidance for the verification and validation of greenhouse gas statements, published by the International Organization for Standardization, as it read on May 1, 2019. (norme ISO 14064-3:2019)

ISO Standard 19011

means the International Standard ISO 19011, entitled Guidelines for auditing management systems, published by the International Organization for Standardization. (norme ISO 19011)

liquid class

means a class of fuel consisting of the fossil fuels that are liquid at standard conditions. (catégorie des combustibles liquides)

low-carbon-intensity fuel

means a liquid or gaseous fuel that is not a fuel in the liquid class or gaseous class and that has a carbon intensity, for the compliance period during which the fuel was produced or imported, that does not exceed

(a) 90% of the reference carbon intensity set out for that compliance period in item 1, column 2, of Schedule 1, in the case of a fuel that is in the liquid state at standard conditions;
(b) the reference carbon intensity set out for that compliance period in item 2, column 2, of Schedule 1, in the case of compressed renewable natural gas and liquefied renewable natural gas referred to in subsection 99(1), renewable natural gas referred to in subsection 100(1) or hydrogen referred to in paragraph 104(1)(b);
(c) the reference carbon intensity set out for that compliance period in item 3, column 2, of Schedule 1, in the case of renewable propane referred to in subsection 99(1) or 100(1) and co-processed low-carbon-intensity propane referred to in subsection 99(1);
(d) 90% of the reference carbon intensity set out for that compliance period in item 2, column 2, of Schedule 1, in the case of biogas or in the case of renewable natural gas and hydrogen that is not referred to in paragraph (b); or
(e) 90% of the reference carbon intensity set out for that compliance period in item 3, column 2, of Schedule 1, in the case of renewable propane and co-processed low-carbon-intensity propane that is not referred to in paragraph (c). (combustible à faible intensité en carbone)

marine vessel

means any boat, ship or other vessel that is designed, used or capable of being used for navigation in, on or through water but is not designed for self-propulsion out of water. (navire)

Methods for Verification and Certification

means the document entitled Methods for Verification and Certification — Clean Fuel Regulations that is developed and published by the Minister. (Méthodes de vérification et de certification)

misstatement

means an error, ommission or misreporting, as defined in Methods for Verification and Certification, in an application or report referred to in these Regulations. (déclaration erronée)

participant

means a primary supplier who is registered with the Minister in accordance with subsection 10(1) or a registered creator who participates in the compliance-credit transfer system. (participant)

petroleum feedstock

means crude oil or a substance derived from crude oil or natural gas, if it is primarily used as a feedstock to produce a fossil fuel in a petroleum refinery or upgrader facility, but it does not include any feedstock that is derived from petrochemicals or other hydrocarbon streams that have undergone additional processing, such as gas-to-liquid processing. (charge d’alimentation à base de pétrole)

primary supplier

means a person who

(a) owns, leases, operates, controls or manages a fuel production facility in Canada at which gasoline or diesel is produced; or
(b) imports gasoline or diesel into Canada. (fournisseur principal)

provisional compliance credit

means a compliance credit referred to in subsection 23(1). (unité de conformité provisoire)

reduction requirement

means the reduction requirement determined in accordance with section 9. (exigence de réduction)

registered creator

means a person registered with the Minister in accordance with subsection 25(1). (créateur enregistré)

renewable natural gas

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

renewable propane

means a mixture that is gaseous at standard conditions, is recovered from the processing of biomass and consists primarily of propane, but it does not include co-processed low-carbon-intensity propane. (propane renouvelable)

residue

means a substance that is produced in a production process but whose production is not a primary aim of the process. It does not include any substance that the process has been deliberately modified to produce. (résidu)

scheme owner

has the same meaning as in subclause 3.11 of ISO/IEC Standard 17065. (propriétaire du régime)

Specifications for Fuel LCA Model CI Calculations

means the specifications that are developed and published by the Minister in respect of the calculation of the carbon intensity of a fuel, energy source or material input using the Fuel LCA Model. (spécifications pour le calcul de l’IC au moyen du modèle ACV des combustibles)

standard conditions

means a temperature of 15°C (59°F) and a pressure of 101.325 kPa (14.696 psia). (conditions normales)

total reduction requirement

means the sum of the reduction requirements in respect of gasoline and diesel for the compliance period that ended most recently, and the deferred portion of the reduction requirements for each preceding compliance period. (exigence de réduction totale)

verification body

means a verification body referred to in section 137. (organisme de vérification)

Hydrogen used as energy source

(2) For the purposes of these Regulations, hydrogen referred to in paragraph 104(1)(a) is deemed to be a low-carbon-intensity fuel if the carbon intensity of the hydrogen, for the compliance period during which the hydrogen is used, does not exceed the reference carbon intensity set out for that compliance period in item 2, column 2, of Schedule 1.

Compressed gas and liquefied gas

(3) In these Regulations,

(a) a reference to hydrogen includes compressed hydrogen and liquefied hydrogen;
(b) a reference to natural gas includes compressed natural gas and liquefied natural gas; and
(c) a reference to renewable natural gas includes compressed renewable natural gas and liquefied renewable natural gas.

Co-processed low-carbon-intensity fuel

(4) The following provisions do not apply in respect of a co-processed low-carbon-intensity fuel:

(a) paragraphs 19(1)(b) and (c);
(b) paragraphs 20(b) and (c);
(c) paragraphs 57(1)(b) and (2)(d);
(d) subsection 59(2);
(e) section 75;
(f) section 76;
(g) subsection 86(2) and (8);
(h) section 91;
(i) section 94;
(j) section 95;
(k) subsection 97(2);
(l) section 100;
(m) section 108;
(n) section 123;
(o) sections 5 and 6 of Schedule 3; and
(p) sections 1 to 6 of Schedule 14; and
(q) section 8 of Schedule 15.

Incorporation by reference

2 (1) A standard or method that is incorporated by reference in these Regulations, other than ISO Standard 14064-3:2019, is incorporated as amended from time to time.

Interpretation of documents incorporated by reference

(2) For the purpose of interpreting any document that is incorporated by reference in these Regulations, a reference to “should” in the English version of the document is to be read as “must” and any recommendation or suggestion is to be read as an obligation unless the context requires otherwise. For greater certainty, in the case of the accuracy or precision of a measurement, the context never requires otherwise.

Inconsistencies with these Regulations

(3) In the event of an inconsistency between a provision in a document incorporated by reference into these Regulations and any provision of these Regulations, the provision of these Regulations prevails to the extent of the inconsistency.

Standard conditions

3 Unless otherwise specified, a reference in these Regulations to a volume or quantity of gas or liquid that is expressed in cubic metres is a reference to the volume or quantity of that gas or liquid at standard conditions.

Application

Exemption — primary suppliers

4 (1) A primary supplier who produces in Canada or imports into Canada a volume of less than 400 m³ of gasoline or a volume of less than 400 m³ of diesel during a compliance period is exempt from the application of these Regulations with respect to that fuel for that compliance period.

Non-application — certain fuels

(2) These Regulations do not apply in respect of gasoline or diesel that is

(a) aviation gasoline;
(b) exported from Canada;
(c) used for scientific research, other than research on consumer preferences in respect of various properties of fuels or market research; or
(d) sold or delivered for the purpose of supplying the engine of a vehicle, including a marine vessel, that is used exclusively for competition.

Exception

(3) However, a primary supplier who, during a compliance period, produces in Canada or imports into Canada a volume of 400 m³ or more of gasoline or diesel must record the volume of every fuel referred to in paragraphs (2)(a) to (d) that is produced or imported during that compliance period and must include that information in the compliance report submitted to the Minister under section 127.

Clarification

(4) For greater certainty, the fuels referred to in paragraphs (2)(a) to (d) are not included when determining, for the purposes of subsection (1), the volume of fuel that is produced in Canada or imported into Canada by a primary supplier.

Requirements for Liquid Fuels

Carbon-Intensity Limits

Requirement — carbon intensity

5 (1) For the purposes of section 139 of the Act, a primary supplier’s pool — as determined in accordance with section 8 — of a liquid fossil fuel that is set out in column 1 of the table to this subsection must not have a carbon intensity that is greater than the corresponding limit set out in column 2 for the corresponding compliance period.

TABLE

Fuel Carbon-Intensity Limits
Item	Column 1 Liquid Fossil Fuel	Column 2 Limit for Each Compliance Period (gCO₂e/MJ)
Item	Column 1 Liquid Fossil Fuel	2023	2024	2025	2026	2027	2028	2029	2030 and after
1	Gasoline	91.5	90.0	88.5	87.0	85.5	84.0	82.5	81.0
2	Diesel	89.5	88.0	86.5	85.0	83.5	82.0	80.5	79.0

Lowering of carbon intensity

(2) A primary supplier must comply with subsection (1) with respect to a fuel for a compliance period by lowering the carbon intensity of their pool of that fuel for that compliance period by an amount that is equal to the difference between the baseline carbon intensity for that fuel and the limit set out in the table to subsection (1) for that fuel and that compliance period. The carbon intensity must be lowered by using compliance credits in accordance with section 11 to satisfy the reduction requirement for that compliance period.

Baseline carbon intensity

(3) For the purposes of subsection (2), the baseline carbon intensity of gasoline is 95 gCO₂e/MJ and the baseline carbon intensity of diesel is 93 gCO₂e/MJ.

Non-application

(4) Subsection (1) does not apply in respect of a fuel that is produced in Canada or imported into Canada before July 1, 2023.

Volumetric requirement — gasoline

6 (1) For the purposes of section 139 of the Act, at least 5% of the volume of a primary supplier’s pool of gasoline — as determined in accordance with section 8 — must, for each compliance period, be displaced by an equivalent volume of a gasoline replacement.

Exception — Newfoundland and Labrador

(2) For the purposes of subsection (1), the primary supplier may, for a compliance period, subtract from their pool of gasoline determined in accordance with section 8 any volume of gasoline that, during the compliance period, the primary supplier produced in or imported into Newfoundland and Labrador and sold or delivered for use in that province, if the primary supplier records information that establishes that the volume of gasoline met those conditions.

Non-application

(3) Subsection (1) does not apply in respect of gasoline that is produced in Canada or imported into Canada before July 1, 2023.

Volumetric requirement — diesel

7 (1) For the purposes of section 139 of the Act, at least 2% of the volume of a primary supplier’s pool of diesel — as determined in accordance with section 8 — must, for each compliance period, be displaced by an equivalent volume of a diesel replacement.

Exception — Newfoundland and Labrador

(2) For the purposes of subsection (1), the primary supplier may, for a compliance period, subtract from their pool of diesel determined in accordance with section 8 any volume of diesel that, during the compliance period, the primary supplier produced in or imported into Newfoundland and Labrador and sold or delivered for use in that province, if the primary supplier records information that establishes that the volume of diesel met those conditions.

Non-application

(3) Subsection (1) does not apply in respect of diesel that is produced in Canada or imported into Canada before July 1, 2023.

Pool of liquid fuel — volume

8 (1) A primary supplier must, for each compliance period, determine the total volume, expressed in cubic metres, of their pool of gasoline or diesel, as the case may be, that was

(a) produced by the primary supplier at a fuel production facility in Canada and, during the compliance period, either
- (i) dispatched from the fuel production facility, or
- (ii) used to fuel a vehicle or other mobile equipment at the fuel production facility; or
(b) imported by the primary supplier into Canada during the compliance period.

Subtraction from pool

(2) However, a primary supplier may, for each compliance period, subtract from their pool of gasoline or diesel, as the case may be, any volume of that fuel, if the primary supplier, before the August 1 of the calendar year that follows the end of the compliance period, records information that establishes that the volume of fuel met any of the following conditions during the compliance period:

(a) it was sold or delivered for a use other than combustion;
(b) it was sold or delivered for use in a marine vessel that had a non-Canadian port as its destination;
(c) it was sold or delivered for use for non-industrial purposes in a geographic area that is served by neither an electrical distribution network that is subject to the standards of the North American Electric Reliability Corporation nor a natural gas distribution system;
(d) it was sold or delivered for the purpose of space heating;
(e) it was sold or delivered for use in the generation of electricity in a geographic area that is served by neither an electrical distribution network that is subject to the standards of the North American Electric Reliability Corporation nor a natural gas distribution system.

Reduction Requirement

Reduction in tonnes

9 The carbon intensity of a pool of gasoline or diesel for a compliance period is considered to be lowered for the purposes of subsection 5(2) if the number of tonnes of CO₂e released over the life cycle of that fuel is reduced by the value of the reduction requirement for that compliance period, as determined by the formula

CI_diff × (Q × D) × 10^-6: where
CI_diff: is the difference, expressed in gCO₂e/MJ, between the baseline carbon intensity of that fuel, as set out in subsection 5(3), and the limit for that fuel for that compliance period, as set out in column 2 of the table to subsection 5(1);
Q: is the volume of that pool for the compliance period, as determined in accordance with section 8 and expressed in cubic metres; and
D: is, at the election of the primary supplier, the energy density of the fuel as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations.

Registration as Primary Supplier

Registration report

10 (1) A primary supplier must register with the Minister by submitting a registration report to the Minister that contains the information referred to in sections 1 to 3 of Schedule 3 no later than 45 days after the day on which they have produced in Canada or imported into Canada, during a compliance period, a total volume of 400 m³ or more of gasoline or a total volume of 400 m³ or more of diesel.

Exception — registration within 90 days

(2) However, the registration report may be submitted at any time during the period that begins on the day on which these Regulations are registered and ends 90 days after that day.

Change of information

(3) If there are any changes in the information referred to in section 1 of Schedule 3 that is provided in the registration report, the primary supplier must send a notice to the Minister that provides the updated information within 30 days after the day on which the change occurs.

Notice of cancellation

(4) A primary supplier who is not required by subsection (1) to be registered for a given compliance period and who has complied with the requirements set out in these Regulations for all of the previous compliance periods, including the volumetric requirements set out in subsections 6(1) and 7(1) and the reduction requirement, may cancel their registration as a primary supplier by sending a notice to that effect to the Minister.

Cancellation by Minister

(5) If, after receiving the notice referred to in subsection (4), the Minister is satisfied that the primary supplier has complied with these Regulations for all previous compliance periods, the Minister must

(a) if the primary supplier is not a registered creator, cancel any compliance credits in their accounts opened under section 28;
(b) cancel their registration as a primary supplier; and
(c) send a notice to the primary supplier informing them that their registration has been cancelled.

Clarification

(6) For greater certainty, subsection (1) applies to a primary supplier whose registration was cancelled by the Minister under subsection (5).

Compliance Credits

Use

Satisfaction of reduction requirement

11 (1) A primary supplier must use the compliance credits that they create under sections 19 and 20, or that are transferred to them under the compliance-credit transfer system, to satisfy the total reduction requirement.

Deemed reduction

(2) The use of one compliance credit by a primary supplier for gasoline or diesel that is produced in Canada or imported into Canada during a compliance period is deemed to reduce by one tonne the quantity of CO₂e released over the life cycle of that fuel during that compliance period.

Prior creation of provisional credit

(3) The primary supplier must use only the compliance credits that are created as provisional compliance credits before the end of a compliance period or the compliance credits that they create under subsection 19(2) to satisfy the reduction requirement for that compliance period.

Cancellation after use

(4) The Minister must cancel a compliance credit immediately after it is used.

Deemed compliance — gasoline

12 (1) For the purposes of subsection 6(1), a compliance credit that was created under paragraph 19(1)(a), (b) or (c) by producing in Canada or importing into Canada a volume of a gasoline replacement, and that is used by a primary supplier in accordance with section 11 for a compliance period, is deemed to displace, for that compliance period, the use of an equivalent volume of the primary supplier’s pool of gasoline.

Deemed compliance — diesel

(2) For the purposes of subsection 7(1), a compliance credit that was created under paragraph 19(1)(a), (b) or (c) by producing in Canada or importing into Canada a volume of a diesel replacement, and that was used by a primary supplier in accordance with section 11 for a compliance period, is deemed to displace, for that compliance period, the use of an equivalent volume of the primary supplier’s pool of diesel.

Prior creation of provisional credit

(3) The primary supplier must use only the compliance credits that are created as provisional compliance credits before the end of a compliance period to comply with the volumetric requirements set out in subsections 6(1) and 7(1) for that compliance period.

July 31 — gasoline

13 (1) For the purposes of subsection 12(1), a primary supplier must, no later than the July 31 that follows the end of a compliance period, use — in accordance with subsection 12(3) — the compliance credits that are in their account opened under paragraph 28(a), until

(a) the volumetric requirement set out in subsection 6(1) is met for that compliance period; or
(b) no such compliance credits remain in that account.

July 31 — diesel

(2) For the purposes of subsection 12(2), a primary supplier must, no later than the July 31 that follows the end of a compliance period, use — in accordance with subsection 12(3) — the compliance credits that are in their account opened under paragraph 28(a), until

(a) the volumetric requirement set out in subsection 7(1) is met for that compliance period; or
(b) no such compliance credits remain in that account.

July 31 — contribution to funding program

(3) For the purposes of section 11 and subject to subsection 15(1), a primary supplier must, no later than the July 31 that follows the end of a compliance period, use all of the compliance credits that they created by contributing to a registered emission-reduction funding program in accordance with paragraph 118(1)(a) to satisfy the reduction requirement for that compliance period.

July 31 — reduction requirement

(4) For the purposes of section 11 and subject to subsections 15(2) and (3), a primary supplier must, no later than the July 31 that follows the end of a compliance period, use the compliance credits that are in their accounts opened under section 28, until

(a) the reduction requirement is satisfied for that compliance period; or
(b) no such compliance credits remain in those accounts.

Choice of compliance credits

(5) Subject to subsections (1) and (2), if the circumstances described in paragraph (4)(a) occur before the circumstances described in paragraph (4)(b), the primary supplier must satisfy the reduction requirement by using compliance credits that are chosen by them and indicated in the report submitted under subsection 127(1).

August 1 — cancellation of credits

(6) On the August 1 that follows the end of a compliance period, if any of the compliance credits referred to in subsection (3) have not been used by the primary supplier, the Minister must cancel those credits.

Non-application — subsections (1) to (4)

(7) Subsections (1) to (4) do not apply in respect of any compliance period that ends before July 1, 2023.

December 15 — gasoline

14 (1) For the purposes of subsection 12(1), if a primary supplier, on the August 1 that follows the end of a compliance period, has not complied with the volumetric requirement set out in subsection 6(1) for that compliance period, the primary supplier must, no later than the following December 15, comply with that requirement by using the compliance credits transferred to them under section 112.

December 15 — diesel

(2) For the purposes of subsection 12(2), if a primary supplier, on the August 1 that follows the end of a compliance period, has not complied with the volumetric requirement set out in subsection 7(1) for that compliance period, the primary supplier must, no later than the following December 15, comply with that requirement by using the compliance credits transferred to them under section 112.

Other credits

(3) For the purposes of section 11 and subject to subsection 15(1), if a primary supplier, on the August 1 that follows the end of a compliance period, has not satisfied the reduction requirement for that compliance period, the primary supplier must, no later than the December 15 that follows the end of that compliance period, use the compliance credits that were transferred to them under section 112, or that they created by contributing to a registered emission-reduction funding program in accordance with paragraph 118(1)(b), to satisfy that reduction requirement.

Compliance — December 15

(4) Subject to sections 16 to 18, a primary supplier must, no later than the December 15 that follows the end of a compliance period, use the compliance credits in their accounts opened under section 28 to satisfy the total reduction requirement and comply with the volumetric requirements set out in subsections 6(1) and 7(1) for that compliance period.

December 16 — cancellation

(5) On the December 16 that follows the expiry of a compliance period, if any of the compliance credits that are referred to in subsection (3) have not been used by the primary supplier, the Minister must cancel those credits.

Non-application — subsections (1) to (4)

(6) Subsections (1) to (4) do not apply in respect of any compliance period that ends before July 1, 2023.

Limits on credit use — funding program

15 (1) The primary supplier must ensure that the total number of compliance credits created under subsection 19(2) — that are used in accordance with subsections 13(3) and 14(3), paragraph 18(1)(a) and subsection 18(3) during the calendar year that follows the end of a compliance period — does not exceed 10% of the primary supplier’s total reduction requirement.

Limit — paragraph 28(b)

(2) The primary supplier must ensure that the total number of compliance credits in their account opened under paragraph 28(b) — that are used in accordance with subsection 13(4) and paragraph 18(1)(b) during the calendar year that follows the end of a compliance period — does not exceed 10% of the primary supplier’s total reduction requirement.

Limit — generic quantification method

(3) The primary supplier must ensure that the total number of compliance credits created under paragraph 19(1)(a) in respect of a project for which a generic emission-reduction quantification method is applicable — that are used in accordance with subsection 13(4) and paragraphs 18(1)(b) and (c) during the calendar year that follows the end of a compliance period — does not exceed 10% of the primary supplier’s total reduction requirement.

Deferral of reduction requirements

16 (1) A primary supplier may, no later than the December 15 that follows the end of a compliance period, defer satisfaction of their reduction requirements for that compliance period by any number of compliance credits that does not exceed the greater of zero and the result of the formula

10% x R_current − R_deferred: where
R_current: is the sum of their reduction requirements in respect of gasoline and diesel for that compliance period; and
R_deferred: is the sum of all deferred portions of the reduction requirements in respect of gasoline and diesel for previous compliance periods.

Conditions for deferral

(2) The primary supplier may defer a portion of their reduction requirements for a compliance period under subsection (1) only if

(a) the Minister has sent a notice in accordance with subsection 111(2) for that compliance period or the primary supplier has acquired by transfer through the compliance-credit clearance mechanism the number of compliance credits determined in accordance with paragraph 112(5)(b) for that compliance period; and
(b) the primary supplier has created enough compliance credits by contributing to a registered emission-reduction funding program to satisfy 10% of the total reduction requirement for that compliance period in respect of all types of fuels.

Compliance required after five years

(3) A primary supplier who defers under subsection (1) a portion of their reduction requirements for a compliance period must satisfy the deferred portion no later than the December 15 that follows the fifth anniversary of the end of that compliance period.

Increase to deferred portion

17 On each December 16 that follows the end of a compliance period for which a portion of the reduction requirements is deferred under subsection 16(1) and that precedes the fifth anniversary of the end of that compliance period, the deferred portion of the reduction requirements is to be multiplied by 1.05.

Reduction — July 31

18 (1) In order to reduce a deferred portion of the reduction requirements in accordance with section 11, the primary supplier must, during the period that begins on the day after a compliance period expires and ends on the July 31 that follows that day, use the following compliance credits that are in their accounts opened under section 28 and that exceed the number required to satisfy the reduction requirements for the compliance period that ended most recently:

(a) subject to subsection 15(1), all of the compliance credits that they created by contributing to a registered emission-reduction funding program in accordance with paragraph 118(1)(a);
(b) subject to subsections 15(2) and (3), any compliance credits in their account opened under paragraph 28(b); and
(c) subject to subsection 15(3), any compliance credits in their account opened under paragraph 28(a).

Election

(2) If the primary supplier has more credits than the number required to satisfy the deferred portion of the reduction requirements in accordance with subsection (1), they may elect to use any number of compliance credits referred to in paragraphs (1)(b) and (c) to satisfy the deferred portion of the reduction requirements.

Reduction — December 15

(3) Subject to subsection 15(1), if a primary supplier, on the August 1 that follows the end of a compliance period, has not satisfied the deferred portion of the reduction requirements for a previous compliance period in accordance with subsection (2), the primary supplier must, no later than the following December 15, reduce the deferred portion of the reduction requirements by using all of the compliance credits in their account opened under paragraph 28(a) — that were transferred to them through the compliance-credit clearance mechanism under section 112 or that they created by contributing to a registered emission-reduction funding program in accordance with paragraph 118(1)(b) — that exceed the number of compliance credits required to satisfy their reduction requirements for the compliance period that ended most recently.

Multiple compliance periods

(4) If a primary supplier has not satisfied the deferred portion of the reduction requirements for more than one previous compliance period, they must not use any compliance credits to reduce the deferred portion of the reduction requirements in accordance with subsection (1) or (3) for a particular compliance period unless they have satisfied the deferred portion of the reduction requirements for every compliance period that precedes that particular compliance period.

Non-application

(5) Subsections (1) to (4) do not apply before January 1, 2025.

Creation

Reduction of CO₂e Emissions

Liquid class

19 (1) A registered creator may create a compliance credit in respect of the liquid class in the following cases:

(a) the registered creator, or a person with whom they have entered into an agreement under section 21, lowers the carbon intensity of a fuel in the liquid class by carrying out, in respect of that fuel, a CO₂e-emission-reduction project that is described in section 30 and that is recognized under subsection 35(1), 36(1), 37(3), 39(1) or 40(3), as the case may be;
(b) the registered creator imports into Canada a quantity of low-carbon-intensity fuel to which may be attributed a reduction in the number of tonnes of CO₂e that would otherwise have been emitted by the use of a fuel in the liquid class, if the low-carbon-intensity fuel
- (i) is in the liquid state at standard conditions,
- (ii) is one referred to in section 94,
- (iii) is used or sold for use as a fuel in Canada whether as neat fuel or as part of a blend, and
- (iv) meets the requirements set out in section 56;
(c) the registered creator, or a person with whom they have entered into an agreement under section 21, produces in Canada a quantity of low-carbon-intensity fuel to which may be attributed a reduction in the number of tonnes of CO₂e that would otherwise have been emitted by the use of a fuel in the liquid class, if the low-carbon-intensity fuel
- (i) is in the liquid state at standard conditions,
- (ii) is one referred to in section 94,
- (iii) is used or sold for use as a fuel in Canada whether as neat fuel or as part of a blend, and
- (iv) meets the requirements set out in section 56; or
(d) the registered creator, or a person with whom they have entered into an agreement under section 21, reduces the number of tonnes of CO₂e emissions by displacing the use in Canada of a quantity of fuel in the liquid class as a fuel for a vehicle with the use in Canada of
- (i) a quantity of propane, compressed natural gas or liquefied natural gas as a fuel for a vehicle, in accordance with section 98,
- (ii) a quantity of renewable propane, co-processed low-carbon-intensity propane, compressed renewable natural gas or liquefied renewable natural gas that meets the requirements set out in section 56 as a fuel for a vehicle, in accordance with section 99,
- (iii) a quantity of renewable propane or renewable natural gas that meets the requirements set out in section 56 as a fuel for a vehicle, in accordance with section 100,
- (iv) a quantity of electricity as an energy source for an electric vehicle, in accordance with sections 101 and 102, or
- (v) a quantity of hydrogen that meets the requirements set out in section 56, in accordance with section 104,
  - (A) as an energy source for a hydrogen fuel cell vehicle, or
  - (B) as a fuel for a vehicle other than a hydrogen fuel cell vehicle.

Contribution to funding program

(2) A primary supplier may create a compliance credit in respect of the liquid class if they make a contribution to a registered emission-reduction funding program in accordance with section 118.

Gaseous class

20 A registered creator may create a compliance credit in respect of the gaseous class in the following cases:

(a) the registered creator, or a person with whom they have entered into an agreement under section 21, lowers the carbon intensity of a fuel in the gaseous class by carrying out, in respect of that fuel, a CO₂e-emission-reduction project described in paragraph 30(d) that reduces the carbon intensity of a fuel in the liquid class and is recognized under subsection 36(1), 37(3), 39(1) or 40(3), as the case may be;
(b) the registered creator imports into Canada a quantity of low-carbon-intensity fuel to which may be attributed a reduction in the number of tonnes of CO₂e that would otherwise have been emitted by the use of a fuel in the gaseous class, if the low-carbon-intensity fuel
- (i) is biogas, renewable natural gas, renewable propane or hydrogen,
- (ii) is one referred to in section 95,
- (iii) is used or sold for use as a fuel in Canada whether as neat fuel or as part of a blend, and
- (iv) meets the requirements set out in section 56; or
(c) the registered creator, or a person with whom they have entered into an agreement under section 21, produces in Canada a quantity of low-carbon-intensity fuel to which may be attributed a reduction in the number of tonnes of CO₂e that would otherwise have been emitted by the use of a fuel in the gaseous class, if the low-carbon-intensity fuel
- (i) is biogas, renewable natural gas, renewable propane or hydrogen,
- (ii) is one referred to in section 95 or 96, as the case may be,
- (iii) is used or sold for use as a fuel in Canada whether as neat fuel or as part of a blend, and
- (iv) meets the requirements set out in section 56.

Agreement to create credits

21 (1) A registered creator may, before they have created any provisional compliance credits, enter into an agreement to create compliance credits for a compliance period

(a) with a person who is carrying out a CO₂e-emission-reduction project described in section 30 or a person who is referred to in subsection 98(1), 99(1), 101(1), 102(1) or 104(1); or
(b) with a producer who is referred to in subsection 94(1), 95(1), 96(1) or 100(1), if the agreement applies only to the creation of compliance credits through the production of a quantity of low-carbon-intensity fuel in Canada.

Validity of agreement — requirements

(2) The agreement is not valid unless it is signed by the authorized agents of each of the parties to the agreement and contains the following information:

(a) with respect to each party to the agreement,
- (i) their name, civic address, postal address, telephone number and, if any, email address,
- (ii) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent, and
- (iii) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent;
(b) an indication of the compliance period to which the agreement relates;
(c) if the agreement relates to a CO₂e-emission-reduction project described in section 30,
- (i) the name of the facility at which the project is carried out or, if the equipment with which it is carried out is not within a facility, the name of that equipment,
- (ii) the GPS coordinates to the fifth decimal place and, if any, civic address of that facility or equipment, and
- (iii) an indication of the type of co-processed low-carbon-intensity fuel produced at the facility, if applicable;
(d) if the agreement relates to the production of the fuel referred to in subsection 94(1), 95(1), 96(1) or 100(1) in a facility, with respect to each facility where the fuel is produced,
- (i) the name, GPS coordinates to the fifth decimal place and, if any, civic address of that facility, and
- (ii) an indication of the type of fuel produced at the facility;
(e) if the agreement relates to the supply of a fuel referred to in subsection 98(1) or 99(1) at fuelling stations, with respect to each fuelling station,
- (i) the name, GPS coordinates to the fifth decimal place and, if any, civic address of the fuelling station, and
- (ii) an indication of the type of fuel supplied by the fuelling station;
(f) if the agreement is with a charging-network operator referred to in subsection 102(1), with respect to each charging station in the charging-network operator’s network,
- (i) an indication of the province in which it is located, and
- (ii) an indication of whether it is intended primarily for use by the occupants of a private dwelling-place, for use by the public or for another use;
(g) if the agreement is with a charging-site host referred to in subsection 101(1), with respect to each charging station that the charging-site host owns or leases,
- (i) an indication of the province in which it is located, and
- (ii) the name of the charging-network operator, if any, who operates the communication platform that collects data from the charging station; and
(h) if the agreement is with an owner or operator referred to in subsection 104(1) of one or more hydrogen fuelling stations, the name, GPS coordinates to the fifth decimal place and, if any, civic address of each fuelling station.

Submission to Minister

22 (1) A registered creator who enters into an agreement referred to in section 21 must submit the agreement to the Minister and, subject to subsection (2), must not create provisional compliance credits under the agreement until the day after the day on which it is submitted.

Exception — submission within first 60 days

(2) If the agreement is submitted to the Minister during the first 60 days of the compliance period to which the agreement relates, the registered creator may create provisional compliance credits under the agreement as of the first day of that compliance period unless the agreement provides for a later date.

Creation of Provisional Compliance Credits

Creation of provisional compliance credits

23 (1) Any compliance credit created under subsection 19(1) or section 20 is considered to be a provisional compliance credit at the time that it is created.

No use of provisional credit

(2) A primary supplier must not use a provisional compliance credit to satisfy a total reduction requirement or to comply with any of the volumetric requirements set out in subsections 6(1) and 7(1) and must not transfer a provisional compliance credit under the compliance-credit transfer system.

Single use for creation of provisional credits

(3) A quantity of a fuel or an energy source that has been used by a person to create provisional compliance credits under subsection 94(1), 95(1), 96(1), 98(1), 99(1), 100(1), 101(1), 102(1) or 104(1) must not be used by another person to create compliance credits under the same subsection, and any quantity that is used more than once under the same subsection is deemed not to create any provisional compliance credits.

Loss of provisional status

(4) A provisional compliance credit that is the subject of a credit-creation report submitted under section 120 or 121 ceases to be provisional when the Minister deposits it into a compliance-credit account under subsection 24(1) or (2).

Ownership of provisional credits

(5) On creation, a provisional compliance credit is owned by the registered creator who created it.

Single owner

(6) At any given time, a provisional compliance credit may only have a single owner.

Deposit into account

24 (1) The compliance credits that are the subject of a credit-creation report submitted under section 120 or 121 must be deposited by the Minister as soon as feasible after the reception of the report into the registered creator’s account that was opened under

(a) paragraph 28(a), in the case of a compliance credit created under subsection 19(1); and
(b) paragraph 28(b), in the case of a compliance credit created under section 20.

Deposit — adjustment of credits

(2) The compliance credits created under section 88, 89 or 90 that are the subject of a credit-creation report submitted under section 120 or a credit-adjustment report submitted under section 122 must be deposited by the Minister as soon as feasible after the reception of the report into any of the registered creator’s compliance-credit accounts opened under section 28.

Identification number

(3) The Minister must assign an identification number to each compliance credit when it is deposited into a compliance-credit account.

Registration as Registered Creator

Registration report

25 (1) A person who wishes to create compliance credits under subsection 19(1) or section 20 or under an agreement referred to in section 21 may register with the Minister as a registered creator by submitting to the Minister a registration report containing the information referred to in section 1 of Schedule 3 and any applicable information referred to in sections 4 to 12 of that Schedule.

Registration before creation

(2) A registered creator must not create provisional compliance credits under subsection 19(1) or section 20 until the day after the day on which they become a registered creator.

Exception — registration within 60 days

(3) However, a person who submits a registration report to the Minister during the period that begins on the day on which these Regulations are registered and ends 60 days after that day may create provisional compliance credits as of that day.

Change of information

26 (1) If there are any changes in the information referred to in section 1 of Schedule 3 that is provided in the registration report, the registered creator must send a notice to the Minister that provides the updated information within 30 days after the day on which the change occurs.

Sections 4 to 12 of Schedule 3

(2) If there are any changes in the information referred to in sections 4 to 12 of Schedule 3 that is provided in the registration report, the registered creator must send a notice to the Minister that provides the updated information no later than on the next day on which they are required to submit a report under subsection 120(1) or 121(1).

New agreement

(3) A registered creator who enters into an agreement under section 21 must send a notice to the Minister that contains, in respect of the activities carried out by the person with whom they have entered into the agreement, the information referred to in section 1 of Schedule 3 and any applicable information referred to in sections 4 to 12 of that Schedule.

Cancellation of registration

27 (1) A registered creator may cancel their registration as a registered creator if they

(a) send to the Minister a notice that indicates their intention to cancel their registration; and
(b) submit to the Minister any report or send any notice that they are required by these Regulations to submit or send.

Cancellation by Minister

(2) If, after receiving the notice referred to in paragraph (1)(a), the Minister is satisfied that the registered creator has complied with these Regulations, the Minister must

(a) in the case of a registered creator who is not a primary supplier, cancel any compliance credits in any of the registered creator’s accounts opened under section 28;
(b) cancel the registered creator’s registration as a registered creator; and
(c) send a notice to the registered creator informing them that their registration is cancelled.

Compliance-Credit Accounts

Opening

28 On the registration of a primary supplier under subsection 10(1) or a registered creator under subsection 25(1), the Minister must open the following accounts for the primary supplier or the registered creator in the compliance-credit transfer system:

(a) a liquid-fuel-compliance-credit account; and
(b) a gaseous-fuel-compliance-credit account.

Credit remains in account

29 A compliance credit that is deposited into an account must remain in that account until the compliance credit is cancelled or transferred.

CO₂e-Emission-Reduction Project

Series of activities

30 A CO₂e-emission-reduction project must consist of a series of activities that, when carried out, result in

(a) a reduction of the number of tonnes of CO₂e emissions that are released during the activities carried out over the life cycle of a fossil fuel in the liquid state at standard conditions, including all emissions associated with the extraction of the hydrocarbons used to produce the fuel, with the processing, refining or upgrading of those hydrocarbons to produce the fuel, with the transportation or distribution of those hydrocarbons or the fuel and with the combustion of the fuel;
(b) the sequestration of any CO₂e emissions that are released during the activities carried out over the life cycle of a fossil fuel in the liquid state at standard conditions, including all emissions associated with the extraction of the hydrocarbons used to produce the fuel, with the processing, refining or upgrading of those hydrocarbons to produce the fuel, with the transportation or distribution of those hydrocarbons or the fuel and with the combustion of the fuel;
(c) the use of any CO₂e emissions that are released during the activities carried out over the life cycle of a fossil fuel in the liquid state at standard conditions, including all emissions associated with the extraction of the hydrocarbons used to produce the fuel, with processing, refining or upgrading those hydrocarbons to produce the fuel, with the transportation or distribution of those hydrocarbons or the fuel and with the combustion of the fuel; or
(d) the production of a quantity of co-processed low-carbon-intensity fuel to which may be attributed a reduction in the number of tonnes of CO₂e that would otherwise have been emitted by the use of a fuel in the liquid class or gaseous class, if the co-processed low-carbon-intensity fuel
- (i) is used or sold for use as a fuel in Canada whether as neat fuel or as part of a blend, and
- (ii) meets the requirements set out in section 56.

Generic quantification method

31 (1) The Minister may establish a generic emission-reduction quantification method that is applicable to any project for which no specific emission-reduction quantification method is applicable on the day on which the project is recognized under subsection 35(1) or 39(1).

Conditions

(2) The generic emission-reduction quantification method must

(a) be consistent with ISO Standard 14064-2;
(b) establish a period of 10 years, beginning on the later of the day on which the Minister recognizes a project to which it is applicable and any preferred day referred to in paragraph 34(2)(b), at the end of which the carrying out of the project ceases to create compliance credits; and
(c) indicate that it is applicable to projects carried out in Canada or indicate that it is applicable to projects carried out in a specified foreign country or subdivision of a foreign country that has an agreement with Canada referred to in paragraph 39(1)(b).

Specific quantification method

32 (1) The Minister may establish a specific emission-reduction quantification method that is applicable to a project of a specific type.

Conditions

(2) The specific emission-reduction quantification method must

(a) be consistent with ISO Standard 14064-2;
(b) be based on data that are verifiable for a specified period
(c) be based on emission factors that are considered by generally recognized scientific sources
- (i) to be appropriate for the quantification of the reduction, sequestration or use of CO₂e emissions for the project, and
- (ii) to not result in an overestimate of that quantification;
(d) establish a period of no less than 10 years, beginning on the later of the day on which the Minister recognizes the project and any preferred day referred to in paragraph 34(2)(b), at the end of which the carrying out of the project ceases to create compliance credits;
(e) identify the data that are necessary to determine the number of compliance credits created under paragraph 19(1)(a) or 20(a) by the carrying out of the project for a specified period; and
(f) indicate that it is applicable to projects carried out in Canada or indicate that it is applicable to projects carried out in a specified foreign country or subdivision of a foreign country that has an agreement with Canada referred to in paragraph 39(1)(b).

Exception

33 Despite sections 31 and 32, no emission-reduction quantification method is applicable to, and no compliance credits are created under paragraph 19(1)(a) or 20(a) by any of the following types of projects:

(a) projects that include an operational or physical change that is solely for the purpose of reducing the production of fuel;
(b) projects that are maintenance activities;
(c) projects that include a reduction in the number of tonnes of CO₂e emissions by displacing the use of a type of crude oil processed by a facility with the use of another type of crude oil;
(d) projects that consist of current practices that would be carried out in the ordinary course of business;
(e) projects that include a reduction in the number of tonnes of CO₂e emissions that are released during the extraction of the hydrocarbons used to produce a fuel, during the processing, refining or upgrading of those hydrocarbons to produce the fuel, during the transportation or distribution of those hydrocarbons or the fuel and during the combustion of the fuel by displacing the use of that fuel with the use of fuel, hydrogen or electricity for which compliance credits may be created under any of sections 94, 96, 98 to 102 and 104.

Application for recognition

34 (1) A registered creator may apply to the Minister for the recognition of a CO₂e-emission-reduction project described in section 30 as a project that may create compliance credits when carried out in Canada.

Contents of application

(2) The application must be signed by the authorized agent of the registered creator and contain

(a) the information referred to in Schedule 4;
(b) if the registered creator prefers that the carrying out of the project may create provisional compliance credits only as of a particular day, which must be no later than 18 months after the day on which the application is made, an indication of that preferred day; and
(c) an indication that the registered creator is applying to use a generic emission-reduction quantification method or a specific emission-reduction quantification method, whichever is applicable to the project, and the name of that method.

Recognition — generic quantification method

35 (1) In the case of an application under subsection 34(1) for the recognition of a CO₂e-emission-reduction project and the use of a generic emission-reduction quantification method that is applicable to the project, the Minister must recognize the project as a project that may create compliance credits when carried out if the Minister is satisfied, based on the information provided by the registered creator, that

(a) the activities that result in the reduction, sequestration or use of CO₂e emissions will be carried out in Canada;
(b) the project’s reduction, sequestration or use of CO₂e emissions will be determined using the generic emission-reduction quantification method;
(c) the activity specified in the generic emission-reduction quantification method that allows the project to begin to reduce, sequester or use CO₂e emissions was or will be carried out on or after July 1, 2017;
(d) the specified activities that would have been carried out if not for the implementation of the project and the CO₂e emissions that would have resulted from those activities, as well as the greenhouse gas sources and sinks that have been selected by the applicant to determine those CO₂e emissions,
- (i) are functionally equivalent to the project, in terms of the type and level of activity of products provided,
- (ii) are in accordance with ISO Standard 14064-2 and with the generic emission-reduction quantification method, and
- (iii) do not result in an overestimation of CO₂e emissions resulting from those specified activities that would have been carried out by the applicant; and
(e) the greenhouse gas sources and sinks that have been selected by the applicant and are relevant to the project meet the following conditions:
- (i) they are in accordance with ISO Standard 14064-2 and with the generic emission-reduction quantification method, and
- (ii) they do not result in an underestimation of CO₂e emissions released during the project.

Unique alphanumeric identifier

(2) The Minister must assign a unique alphanumeric identifier to a CO₂e-emission-reduction project recognized under subsection (1).

Number of compliance credits

(3) The number of provisional compliance credits that are created for each compliance period by the carrying out of a project recognized under subsection (1) is determined — in accordance with the generic emission-reduction quantification method — based on the proportion of the quantity of crude oil or liquid fossil fuel that is not exported from Canada and that has a reduced carbon intensity as a result of the activities carried out for the project.

End of project

(4) The carrying out of a project recognized under subsection (1) ceases to create compliance credits as of the end of the period referred to in paragraph 31(2)(b) or, if applicable, the end of the five-year period referred to in subsection 42(1).

Recognition — specific quantification method

36 (1) In the case of an application under subsection 34(1) for the recognition of a CO₂e-emission-reduction project and the use of a specific emission-reduction quantification method that is applicable to the project, the Minister must recognize the project as a project that may create compliance credits when carried out if the Minister is satisfied, based on the information provided to the Minister by the registered creator, that

(a) the activities that result in the reduction, sequestration or use of CO₂e emissions will be carried out in Canada;
(b) the project’s reduction, sequestration or use of CO₂e emissions will be determined using the specific emission-reduction quantification method; and
(c) the activity specified in the specific emission-reduction quantification method that allows the project to begin to reduce, sequester or use CO₂e emissions was or will be carried out on or after July 1, 2017, unless the method provides that the activity may be carried out before that date.

Unique alphanumeric identifier

(2) The Minister must assign a unique alphanumeric identifier to a CO₂e-emission-reduction project recognized under subsection (1).

Number of compliance credits

(3) The number of provisional compliance credits that are created for each compliance period by the carrying out of a project recognized under subsection (1) is determined — in accordance with the specific emission-reduction quantification method — based on the proportion of the quantity of crude oil or liquid fossil fuel that is not exported from Canada and that has a reduced carbon intensity as a result of the activities carried out for the project.

End of project

(4) The carrying out of a project recognized under subsection (1) ceases to create compliance credits as of the end of the period referred to in paragraph 32(2)(d) or, if applicable, the end of the five-year period referred to in subsection 42(1).

Application for recognition — change of method

37 (1) If, after the recognition of a CO₂e-emission-reduction project under subsection 35(1) but before the end of the period referred to in paragraph 31(2)(b) or, if applicable, the five-year period referred to in subsection 42(1), the Minister establishes a specific emission-reduction quantification method under subsection 32(1) that is applicable to the project, the registered creator may apply to the Minister for the recognition of the project as a project that may create compliance credits when carried out in Canada using that method.

Contents of application

(2) The application must be signed by the authorized agent of the registered creator and contain

(a) if the information contained in the original application for recognition under subsection 34(1), other than the information referred to in paragraph 2(d) of Schedule 4, has changed, the updated information;
(b) an indication that the registered creator is applying to use the specific emission-reduction quantification method and the name of that method;
(c) the information referred to in paragraph 2(d) of Schedule 4 in respect of that method; and
(d) if the registered creator prefers that the carrying out of the project may create provisional compliance credits only as of a particular day, an indication of that preferred day, which must be
- (i) no later than 18 months after the day on which the application is made, and
- (ii) before the end of the period referred to in paragraph 31(2)(b) or, if applicable, the five-year period referred to in subsection 42(1).

Recognition by the Minister

(3) The Minister must recognize the CO₂e-emission-reduction project as a project that may create compliance credits when carried out if the Minister is satisfied, based on the information provided by the registered creator, that the project meets the criteria set out in paragraphs 36(1)(a) to (c).

Unique alphanumeric identifier

(4) The Minister must assign a unique alphanumeric identifier to a CO₂e-emission-reduction project recognized under subsection (3).

Period — creation of compliance credits

(5) Subject to subsection 42(4), the period during which the carrying out of the project may create provisional compliance credits begins on the later of the day on which it is recognized under subsection (3) and the preferred day referred to in paragraph (2)(d) and is determined by the formula

S − D: where
S: is the period referred to in paragraph 32(2)(d) and established in the specific emission-reduction quantification method that is applicable to the project, expressed as a number of days; and
D: is the number of days — during the period referred to in paragraph 31(2)(b) — on which the carrying out of the project has created provisional compliance credits using the generic emission-reduction quantification method.

Number of compliance credits

(6) The number of provisional compliance credits that are created for the period determined under subsection (5) or, if applicable, subsection 42(4) by the carrying out of a project that is recognized under subsection (3) is determined — in accordance with the specific emission-reduction quantification method — based on the proportion of the quantity of crude oil or liquid fossil fuel that is not exported from Canada and that has a reduced carbon intensity as a result of the activities carried out for the project.

End of project — generic method

(7) The carrying out of a project that is recognized under subsection (3) ceases to create compliance credits under section 35 as of the day before the day on which the period determined under subsection (5) begins.

End of project — specific method

(8) The carrying out of a project that is recognized under subsection (3) ceases to create compliance credits under subsection (6) as of the end of the period determined under subsection (5) or, if applicable, the end of the five-year period referred to in subsection 42(1).

Application for recognition — project in foreign country

38 (1) A registered creator may apply to the Minister for the recognition of a CO₂e-emission-reduction project that is described in section 30 and carried out in a foreign country or subdivision of a foreign country as a project that may create compliance credits when carried out in the foreign country or subdivision, if there is an agreement referred to in paragraph 39(1)(b) between Canada and that foreign country or subdivision and the agreement is applicable to that type of project.

Contents of application

(2) The application must be signed by the authorized agent of the registered creator and must contain

(a) the information referred to in Schedule 4;
(b) if the registered creator prefers that the carrying out of the project may create provisional compliance credits only as of a particular day, which must be no later than 18 months after the day on which the application is made, an indication of that preferred day; and
(c) an indication that the registered creator is applying to use the applicable generic emission-reduction quantification method or specific emission-reduction quantification method that is indicated in the agreement referred to in subsection (1) and the name of that method.

Recognition — project in foreign country

39 (1) The Minister must recognize a CO₂e-emission-reduction project carried out in a foreign country or subdivision of a foreign country as a project that may create compliance credits when carried out if the Minister is satisfied that

(a) based on the information provided to the Minister by the registered creator, the project meets the criteria set out in subsection (2) or (3), as the case may be; and
(b) Canada has an agreement with the foreign country or the subdivision that meets the requirements set out in subsection (4).

Generic quantification method

(2) In the case of an application under subsection 38(1) for the recognition of a CO₂e-emission-reduction project and the use of a generic emission-reduction quantification method that is applicable to the project, the project must meet the following criteria:

(a) the activities carried out outside Canada during the project that result in the reduction, sequestration or use of CO₂e emissions are comparable in effectiveness with projects that are carried out in Canada with respect to the reduction, sequestration or use of CO₂e emissions released during the activities carried out over the life cycle of a fossil fuel that is in the liquid state at standard conditions;
(b) the activity specified in the generic emission-reduction quantification method that allows the project to begin to reduce, sequester or use CO₂e emissions was or will be carried out on or after July 1, 2017;
(c) the reduction, sequestration or use of CO₂e emissions resulting from the project is determined using the generic emission-reduction quantification method;
(d) the specified activities that would have been carried out if not for the implementation of the project and the CO₂e emissions that would have resulted from those activities, as well as the greenhouse gas sources and sinks that have been selected by the applicant to determine those CO₂e emissions,
- (i) are functionally equivalent to the project, in terms of the type and level of activity of products provided,
- (ii) are in accordance with ISO Standard 14064-2 and with the generic emission-reduction quantification method, and
- (iii) do not result in an overestimation of CO₂e emissions resulting from those specified activities that would have been carried out by the applicant; and
(e) the greenhouse gas sources and sinks that have been selected by the applicant and are relevant to the project meet the following conditions:
- (i) they are in accordance with ISO Standard 14064-2 and with the generic emission-reduction quantification method, and
- (ii) they do not result in an underestimation of CO₂e emissions released during the project.

Specific quantification method

(3) In the case of an application under subsection 38(1) for the recognition of a CO₂e-emission-reduction project and the use of a specific emission-reduction quantification method that is applicable to the project, the project must meet the following criteria:

(a) the activities carried out outside Canada during the project that result in the reduction, sequestration or use of CO₂e emissions are comparable in effectiveness with projects that are carried out in Canada with respect to the reduction, sequestration or use of CO₂e emissions released during the activities carried out over the life cycle of a fossil fuel that is in the liquid state at standard conditions;
(b) the activity specified in the specific emission-reduction quantification method that allows the project to begin to reduce, sequester or use CO₂e emissions was or will be carried out on or after July 1, 2017, unless the method provides that the activity may be carried out before that date; and
(c) the reduction, sequestration or use of CO₂e emissions resulting from the project is determined using the specific emission-reduction quantification method.

Agreement with foreign country or subdivision

(4) An agreement referred to in paragraph (1)(b) with a foreign country or a subdivision of a foreign country must

(a) specify any generic emission-reduction quantification methods and specific emission-reduction quantification methods that are applicable to projects of specific types that are carried out in the foreign country or subdivision;
(b) recognize that the emission reductions that result from those specific types of projects do not result from current practices that would be carried out in the ordinary course of business;
(c) recognize that the emission reductions that result from those specific types of projects are permanent;
(d) recognize that there are environmental laws that are in force in, and enforceable by, the foreign country or the subdivision that are applicable to those specific types of projects and that are comparable to environmental laws in force in Canada in terms of effectiveness;
(e) recognize that there are laws related to the requirement set out in paragraph (c) that are in force in, and enforceable by, the foreign country or the subdivision and that are comparable to environmental laws in force in Canada in terms of effectiveness;
(f) set out how the foreign country or the subdivision will carry out enforcement activities, including the conduct of inspections, compliance verifications and investigations of suspected violations, and how it will enforce compliance with the laws referred to in paragraphs (d) and (e) in a manner that is equivalent to the level of enforcement in Canada; and
(g) set out how the foreign country or the subdivision will cooperate and share information with Canada to assist in the administration and enforcement of these Regulations.

Unique alphanumeric identifier

(5) The Minister must assign a unique alphanumeric identifier to a CO₂e-emission-reduction project recognized under subsection (1).

End of project

(6) The carrying out of a project that is recognized under subsection (1) ceases to create compliance credits under section 41 on the earlier of

(a) the end of the period referred to in paragraph 31(2)(b) or, if applicable, the end the five-year period referred to in subsection 42(1), and
(b) the day on which Canada no longer has an agreement with the foreign country or subdivision of a foreign country in which the project is carried out.

Application for recognition — change of method

40 (1) If, after the recognition of a CO₂e-emission-reduction project under subsection 39(1) as a project that may create compliance credits using a generic emission-reduction quantification method, but before the end of the period referred to in paragraph 31(2)(b) or, if applicable, the five-year period referred to in subsection 42(1), the Minister establishes a specific emission-reduction quantification method under subsection 32(1) that is applicable to the project and the agreement referred to in paragraph 39(1)(b) is amended to permit the use of that specific emission-reduction quantification method for that type of project, the registered creator may apply to the Minister for the recognition of the project as a project that may create compliance credits when carried out using that specific emission-reduction quantification method.

Contents of application

(2) The application must be signed by the authorized agent of the registered creator and must contain

(a) if the information contained in the original application for recognition of the project under subsection 38(1), other than the information referred to in paragraph 2(d) of Schedule 4, has changed, the updated information;
(b) an indication that the registered creator is applying to use the specific emission-reduction quantification method and the name of that method;
(c) the information referred to in paragraph 2(d) of Schedule 4 in respect of that method; and
(d) if the registered creator prefers that the carrying out of the project may create provisional compliance credits only as of a particular day, an indication of the preferred day, which must be
- (i) no later than 18 months after the day on which the application is made, and
- (ii) before the end of the period referred to in paragraph 31(2)(b) or , if applicable, the five-year period referred to in subsection 42(1).

Recognition by the Minister

Unique alphanumeric identifier

(4) The Minister must assign a unique alphanumeric identifier to a CO₂e-emission-reduction project recognized under subsection (3).

Creation of compliance credits

(5) Subject to subsection 42(4), the period during which the carrying out of the project may create provisional compliance credits begins on the later of the day on which the project is recognized under subsection (3) and the preferred day referred to in paragraph (2)(d) and is determined by the formula

S − D: where
S: is the period referred to in paragraph 32(2)(d) and established in the specific emission-reduction quantification method that is indicated in the agreement referred to in paragraph 39(1)(b) and that is applicable to the project, expressed as a number of days; and
D: is the number of days — during the period referred to in paragraph 31(2)(b) — on which the carrying out of the project has created provisional compliance credits using the generic emission-reduction quantification method.

End of project — generic method

(6) The carrying out of a CO₂e-emission-reduction project that is recognized under subsection (3) ceases to create compliance credits under section 39 on the earlier of

(a) the day before the day on which the period determined under subsection (5) begins, and
(b) the day on which Canada no longer has an agreement with the foreign country or subdivision of a foreign country in which the project is carried out.

End of project — specific method

(7) The carrying out of a project that is recognized under subsection (3) ceases to create compliance credits under section 41 as of the end of the period determined under subsection (5) or, if applicable, the end of the five-year period referred to in subsection 42(1).

Number of compliance credits — projects in foreign country

41 The number of provisional compliance credits that are created by the carrying out of a CO₂e-emission-reduction project recognized under subsection 39(1) or 40(3) is determined — in accordance with the emission-reduction quantification method that is indicated in the agreement referred to in paragraph 39(1)(b) and that is applicable to the project — based on the proportion of the quantity of crude oil or liquid fossil fuel that is imported into Canada and that has a reduced carbon intensity as a result of the activities carried out for the project.

Extension of period — five years

42 (1) Subject to subsection (3), during the year that precedes the end of the period referred to in paragraph 31(2)(b) or 32(2)(d) or determined under subsection 37(5) or 40(5), as the case may be, a registered creator may apply to the Minister to extend that period for a single period of five years.

Application — contents

(2) The application for extension must be signed by the authorized agent of the registered creator and, if there are any changes in the information provided in the original application for recognition of the CO₂e-emission-reduction project, the application for extension must provide the updated information.

No extension

(3) In the case of a CO₂e-emission-reduction project that was recognized under subsection 35(1) or 39(1) as a project that may create compliance credits when carried out using a generic emission-reduction quantification method, no application for extension may be made if, during the year that precedes the end of the period established under paragraph 31(2)(b), the Minister establishes a specific emission-reduction quantification method under subsection 32(1) that is applicable to the project.

Extension after change of method

(4) If, during the five-year extension period granted by the Minister in respect of a CO₂e-emission-reduction project that was recognized under subsection 35(1) or 39(1) as a project that may create compliance credits when carried out using a generic emission-reduction quantification method, the Minister recognizes the project under subsection 37(3) or 40(3) as a project that may create compliance credits when carried out using a specific emission-reduction quantification method, the period during which the project may create provisional compliance credits begins on the later of the day on which the project is recognized under subsection 37(3) or 40(3) and the preferred day referred to in paragraph 37(2)(d) or 40(2)(d), as the case may be, and is determined by the formula

P − D: where
P: is the five-year extension period granted by the Minister, expressed as a number of days; and
D: is the number of days — during the period P — on which the carrying out of the project has created provisional compliance credits using the generic emission-reduction quantification method.

Federal or provincial laws

43 If an activity that is carried out as part of a CO₂e-emission-reduction project ceases to be additional to what is required by the laws of Canada or of a province — other than any laws relating to greenhouse gas emission pricing mechanisms, the reduction of the carbon intensity of fuel or the use of low-carbon-intensity fuel — the number of provisional compliance credits that are created under subsections 35(3), 36(3) and 37(6) and section 41 by the carrying out of the project is reduced in proportion to the reduction of CO₂e emissions that results from that activity.

Failure to comply with record requirements

44 If a registered creator fails to comply with any of the requirements set out in sections 166 and 168 in relation to a CO₂e-emission-reduction project, any compliance credits that are created by carrying out the project during the period of non-conformity with those requirements are not valid and are considered to be excess compliance credits that may be suspended by the Minister under section 158 or cancelled by the Minister under section 160.

Displacement of Fossil Fuel Usage

Land-Use and Biodiversity Criteria for Low-Carbon-Intensity Fuels

Maximum quantity

45 (1) The maximum quantity of a low-carbon-intensity fuel that is produced at a facility by a producer in Canada or foreign supplier during each period referred to in subsection (3) for which compliance credits may be created by the carrying out of a CO₂e-emission-reduction project described in paragraph 30(d) or be created under any of sections 94 to 96, 99, 100 and 104 is determined by the formula

Q_fuel x Q_eligible ÷ (Q_eligible + Q_ineligible): where
Q_fuel: is the quantity of the low-carbon-intensity fuel that is produced at the facility during the period, expressed in kilograms or cubic metres, as applicable;
Q_eligible: is the quantity of eligible feedstock that meets the requirements set out in section 47 that was used at the facility by the producer in Canada or foreign supplier to produce the low-carbon-intensity fuel during the period, expressed in kilograms or cubic metres, as applicable; and
Q_ineligible: is the quantity of feedstock, other than eligible feedstock, that was used at the facility by the producer in Canada or foreign supplier to produce the low-carbon-intensity fuel during the period, expressed in kilograms or cubic metres, as applicable.

Carbon intensity

(2) For the purposes of subsection (1), a low-carbon-intensity fuel is a fuel that

(a) has a carbon intensity to which an alphanumeric identifier has been assigned under subsection 85(2); or
(b) has the default carbon intensity referred to in paragraph 75(1)(a) or determined in accordance with the emission-reduction quantification method that is applicable to a project described in paragraph 30(d).

Periods

(3) The periods for producing low-carbon-intensity fuels are, for any compliance period that ends after January 1, 2024,

(a) the period beginning on the January 1 and ending on the March 31 of the compliance period;
(b) the period beginning on the April 1 and ending on the June 30 of the compliance period;
(c) the period beginning on the July 1 and ending on the September 30 of the compliance period; and
(d) the period beginning on the October 1 and ending on the December 31 of the compliance period.

Exclusive use

(4) A person who uses a quantity of low-carbon-intensity fuel produced from an eligible feedstock 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 must not use that quantity of low-carbon-intensity fuel to create compliance credits by the carrying out of a CO₂e-emission-reduction project referred to in paragraph 30(d) or under any of sections 94 to 96, 99, 100 and 104.

Eligibility requirements

46 (1) Subject to subsection (2) and sections 48 to 55, 57 and 58, the following feedstock is eligible:

(a) feedstock that is not derived from biomass;
(b) feedstock that is derived from
- (i) forest biomass derived from fire prevention and protection activities or from clearing activities that are not related to harvesting, such as infrastructure installation, pest and disease control and road maintenance,
- (ii) crop residues or damaged crops,
- (iii) secondary forest residues that are by-products of industrial wood-processing operations,
- (iv) used or inedible organics from a residential area, retail store, restaurant, caterer or food processing plant,
- (v) used fat or used vegetable oil,
- (vi) used animal litter,
- (vii) animal materials, including manure,
- (viii) industrial effluents,
- (ix) municipal wastewater, or
- (x) used construction or demolition materials; and
(c) feedstock that is derived from agricultural or forest biomass but is not derived from a material or source referred to in paragraph (b).

Intentionally used feedstock

(2) A feedstock that is derived from agricultural or forest biomass and that is intentionally altered in order to meet any of the conditions set out in paragraph (1)(b) is considered not to be an eligible feedstock for the purposes of that paragraph.

Quantity of eligible feedstock

47 (1) The quantity of an eligible feedstock of a particular type that, after December 31, 2023, is removed from the site where it was harvested, mixed, processed, divided or obtained must not be greater than the quantity determined by the formula

Q_inventory + Q_incoming: where
Q_inventory: is the quantity of eligible feedstock of that type that was at the site after the previous time that a quantity of eligible feedstock of that type was removed from the site, expressed in kilograms or cubic metres, as applicable; and
Q_incoming: is the quantity of eligible feedstock of that type that was harvested at or brought to the site since the previous time that a quantity of eligible feedstock of that type was removed from the site, expressed in kilograms or cubic metres, as applicable.

Production of fuel

(2) For each period referred to in subsection 45(3), the total of the quantity of eligible feedstock of a particular type that is used to produce a low-carbon-intensity fuel at a facility and the quantity of eligible feedstock of that type that is at the facility at the end of the period must not be greater than the quantity determined by the formula

Q_inventory + Q_incoming: where
Q_inventory: is the quantity of eligible feedstock of that type that was at the facility at the beginning of the period, expressed in kilograms or cubic metres, as applicable; and
Q_incoming: is the quantity of eligible feedstock of that type that was brought to the facility during the period, expressed in kilograms or cubic metres, as applicable.

Wildlife habitat

48 (1) It is not permitted to harvest feedstock referred to in paragraph 46(1)(c) from land located in an area that provides a habitat for any rare, vulnerable or threatened species.

Exception

(2) However, the Minister may, on application from a person who harvests a feedstock referred to in paragraph 46(1)(c) or who produces fuel from that feedstock, authorize the use of a feedstock obtained from rehabilitation or habitat-improvement activities carried out on land located in an area that provides a habitat referred to in subsection (1) if the Minister is satisfied that those activities do not adversely affect that habitat.

Application

(3) The application must

(a) describe the activities that the person who harvests the feedstock has carried out or intends to carry out in the area; and
(b) demonstrate that the activities will not adversely affect the habitat.

Damaging agents

49 A feedstock referred to in paragraph 46(1)(c) must be harvested and transported in accordance with measures that monitor, prevent and control the introduction, spread and establishment of damaging agents, such as pests, invasive species and disease.

Crops — indirect changes to land use

50 (1) A feedstock referred to in any of subparagraphs 46(1)(b)(ii) to (vi) or paragraph 46(1)(c) that is a crop, crop by-product or crop residue must be produced in a manner that does not create a high risk of an indirect change to land use that adversely affects the environment.

European Commission Delegated Regulation

(2) For the purposes of subsection (1), there is a high risk that the production of a feedstock will cause an indirect change to land use that adversely affects the environment if the value specified for that feedstock in the Annex to the Commission Delegated Regulation (EU) 2019/807 of 13 March 2019 is greater than

(a) 1% in the column entitled “Average annual expansion of production area since 2008 (%)”; and
(b) 10% in the column entitled “Share of expansion into land referred to in Article 29(4)(b) and (c) of Directive (EU) 2018/2001”.

Crops — excluded land

51 (1) It is not permitted to harvest feedstock referred to in paragraph 46(1)(c) that is a crop from land that

(a) has an area greater than 1 ha and was, at any time on or after July 1, 2020,
- (i) a forest that contains trees that are or are capable of reaching a height of 5 m and provide or are capable of providing a canopy cover of more than 10%,
- (ii) a wetland that is periodically saturated with water for a period that is long enough to promote biological activity that is adapted to a wet environment, or
- (iii) a grassland that is dominated by herbaceous or shrub vegetation that has not been cultivated for 10 years or more; or
(b) was never cultivated before July 1, 2020 and was, at any time on or after that day, in a riparian zone.

Definition of riparian zone

(2) In subsection (1), riparian zone means land that is located within 30 m, measured on a slope distance following the topography of the land, of

(a) the high-water mark of a watercourse that is more than 3 m wide; or
(b) the shores of a lake or permanent wetland that has an area greater than 5 ha.

Forest-based feedstock

52 The harvesting of any feedstock referred to in paragraph 46(1)(c) that is derived from forest biomass must be carried out in accordance with a forest management plan that meets the following requirements:

(a) it must be possible for a verification body to evaluate it;
(b) it must be implemented, monitored and kept up to date, based on monitoring results, to promote adaptive management, by the person who is responsible for harvesting the feedstock; and
(c) it must specify the practices to be followed to ensure that
- (i) the management of the land where the feedstock is harvested is carried out in a manner that promotes timely forest regeneration of that land to its pre-harvesting condition using species of trees that are ecologically suited to the site and drawn, if possible, from native species or local genotypes,
- (ii) adverse effects are prevented on naturally regenerated stands containing multi-layered canopies with trees near their maximum longevity as well as standing and fallen dead trees and forest debris at varying stages of decomposition,
- (iii) forest management and related activities in the areas where the feedstock is harvested are carried out in a manner that prevents or mitigates adverse effects on the quantity and quality of the soil, on the quantity and quality of surface and ground water resources and on biodiversity, and
- (iv) forest management and related activities in the areas where the feedstock is harvested are carried out in a manner that maintains the connectivity of watercourses.

Exemption — approval by EPA

53 (1) The Minister may exempt a feedstock that is a crop from the application of section 51 if

(a) the country from which the feedstock originates is the United States or is a country that is covered by the aggregate compliance approach referred to in section 80.1457 of Subchapter C of Chapter I of Title 40 of the United States Code of Federal Regulations; and
(b) the Minister is satisfied that section 80.1457 of Subchapter C of Chapter I of Title 40 of the United States Code of Federal Regulations provides a sufficient level of environmental protection with respect to the land on which the feedstock is harvested.

Effective date of exemption

(2) The exemption takes effect, in the case of the United States, on the day on which this section comes into force or, in the case of any other country, on the later of

(a) the day on which the EPA decides that the country is covered by the aggregate compliance approach, and
(b) the day on which this section comes into force.

Period of validity

(3) The exemption ceases to be valid on the earlier of

(a) in the case of the United States, the day on which the EPA publishes a finding that the 2007 baseline amount of agricultural land in the United States has been exceeded or, in the case of any other country, the day on which the EPA withdraws its approval for that country to be covered by the aggregate compliance approach, and
(b) the day on which the Minister determines that, following the granting of the exemption, amendments have been made to section 80.1457 of Subchapter C of Chapter I of Title 40 of the United States Code of Federal Regulations and, taking into account those amendments, the Minister is no longer satisfied that there is a sufficient level of environmental protection with respect to the land on which the feedstock is harvested.

Exemption — no net expansion

54 (1) The Minister may, on application from the national level of government of a country, exempt a feedstock that is a crop from the application of section 51 if the Minister is satisfied that the country from which the feedstock originates has not, since July 1, 2020, undergone a net expansion of agricultural land, taking into account the following factors:

(a) any net expansion since July 1, 2020 to the national borders within which agricultural land is measured;
(b) the total amount of land within those national borders that was agricultural land on July 1, 2020;
(c) data from the preceding year on the harvesting of land, including satellite data, aerial photography, census data and agricultural survey data;
(d) data on the use of land to harvest crops between July 1, 2020 and the beginning of the preceding year, including satellite data, aerial photography, census data and agricultural survey data;
(e) any factors that have had or may have an effect on the use of agricultural land within those national borders, including agricultural practices, economic considerations and the content, efficacy and enforcement of applicable laws;
(f) the method of identifying which entity will gather and analyze data and submit it to the Minister, as well as the reliability and credibility of that entity;
(g) evidence with respect to whether the data and methods used to evaluate the net expansion of agricultural land are reliable and transparent;
(h) any comments from the public that the Minister receives; and
(i) any information that is necessary to determine whether the country from which the feedstock originates has, since July 1, 2020, undergone a net expansion of agricultural land.

Conditions

(2) The exemption must not be granted by the Minister unless

(a) the national level of government of the country from which the feedstock originates has provided to the Minister, in English or French, information in respect of the factors referred to in paragraphs (1)(a) to (g) and (i);
(b) the national level of government of the country from which the feedstock originates has provided to the Minister a letter, in English or French, that is signed by an individual with a role comparable to a Minister who is responsible for the part of the government with primary expertise in agricultural land-use patterns and agricultural practices, data and statistics and, in the letter, the individual confirms that
- (i) all supporting data for the factors referred to in paragraphs (1)(a) to (g) and (i) have been reviewed by that part of the government, and
- (ii) the data supports the conclusion that the country from which the feedstock originates has not, since July 1, 2020, undergone a net expansion of agricultural land; and
(c) information in respect of the factors referred to in paragraphs (1)(a) to (g) and (i) has been published on the Department of the Environment’s website and the public has been given an opportunity to submit comments with respect to that information and the proposed exemption for a period of at least 60 days.

Period of validity

(3) The exemption takes effect on the day on which it is granted and ceases to be valid one year after that day, unless the Minister grants a subsequent exemption under subsection (1).

Publication

(4) The Minister must publish on the Department of the Environment’s website, for each exemption that is granted under subsection (1) with respect to a feedstock, a notice of the exemption that sets out the name of the country from which the feedstock originates and the date on which the exemption takes effect.

Exemption — other laws

55 (1) The Minister may, on application from a national or subnational level of government of a country, exempt a feedstock that originates from that country from the application of subsection 48(1), section 49 or subparagraph 52(c)(i), (ii), (iii) or (iv) if the Minister is satisfied that the feedstock is

(a) in the case of subsection 48(1), subject to laws that effectively prohibit the harvesting of the feedstock in any area that provides a habitat for any rare, vulnerable or threatened species;
(b) in the case of section 49, subject to laws that effectively require it to be harvested and transported in accordance with measures to monitor, prevent and control the introduction, spread and establishment of damaging agents, such as pests, invasive species and disease;
(c) in the case of subparagraph 52(c)(i), subject to laws that
- (i) effectively promote timely forest regeneration of the land where the feedstock is harvested to its pre-harvesting condition using species of trees that are ecologically suited to the site and drawn, if possible, from native species or local genotypes, and
- (ii) include enforcement requirements for forest regeneration on the land where the feedstock is harvested;
(d) in the case of subparagraph 52(c)(ii), subject to laws that
- (i) effectively prevent adverse effects on naturally regenerating stands containing multi-layered canopies with trees near their maximum longevity as well as standing and fallen dead trees and forest debris at varying stages of decomposition, and
- (ii) include enforcement requirements for the purpose of protecting stands described in subparagraph 52(c)(ii);
(e) in the case of subparagraph 52(c)(iii) as it relates to soil, subject to laws that
- (i) effectively require that forest management and related activities be carried out on the land where the feedstock is harvested in a manner that prevents adverse effects on the quantity and quality of the soil and mitigates any adverse effects that do occur, and
- (ii) include enforcement requirements for the purpose of preventing adverse effects on the quantity and quality of the soil;
(f) in the case of subparagraph 52(c)(iii) as it relates to surface and ground water resources, subject to laws that
- (i) effectively require that forest management and related activities be carried out on the land where the feedstock is harvested in a manner that prevents adverse effects on the quantity and quality of surface and ground water resources and mitigates any adverse effects that do occur, and
- (ii) include enforcement requirements for the purpose of preventing adverse effects on the quantity and quality of surface and ground water resources;
(g) in the case of subparagraph 52(c)(iii) as it relates to biodiversity, subject to laws that
- (i) effectively require that forest management and related activities be carried out on the land where the feedstock is harvested in a manner that prevents adverse effects on biodiversity and mitigates any adverse effects that do occur, and
- (ii) include enforcement requirements for the purpose of preventing adverse effects on biodiversity; and
(h) in the case of subparagraph 52(c)(iv), subject to laws that
- (i) effectively require that forest management and related activities be carried out on the land where the feedstock is harvested in a manner that maintains the connectivity of watercourses, and
- (ii) include enforcement requirements for the purpose of maintaining the connectivity of watercourses.

Language of documents

(2) Any information or document that is relevant to the Minister’s decision regarding whether to exempt a feedstock under subsection (1) must be provided to the Minister in English or French.

Period of validity

(3) An exemption granted under subsection (1) ceases to be valid on the ier of

(a) the day that is seven years after the day on which the exemption is granted by the Minister, and
(b) the day on which the Minister determines that, following the granting of the exemption, amendments have been made to the laws applicable to the exempted feedstock and, taking into account such amendments, the Minister is no longer satisfied that the laws meet the conditions referred to in subsection (1).

Publication

(4) The Minister must publish on the Department of the Environment’s website, for each exemption that is granted under subsection (1) with respect to a feedstock, a notice of the exemption that sets out the title of the laws to which the feedstock is subject and the date on which the exemption takes effect.

Low-carbon-intensity fuel

56 A person must not use a quantity of low-carbon-intensity fuel to create compliance credits by carrying out a CO₂e-emission-reduction project described in paragraph 30(d) or to create compliance credits under any of sections 94 to 96, 99, 100 and 104, unless

(a) the fuel is produced from a quantity of an eligible feedstock that is referred to in paragraph 46(1)(a) and the conditions set out in subsection 57(1) are met in respect of the feedstock; or
(b) the fuel is produced from a quantity of an eligible feedstock that is referred to in paragraph 46(1)(b) or (c), the conditions set out in subsection 57(2) are met in respect of the feedstock and the registered creator who produced the fuel or the foreign supplier ensures that, for each period referred to in subsection 45(3), the quantity of the eligible feedstock that is used at each of their facilities to produce the fuel is less than or equal to the quantity determined by the formula set out in subsection 47(2).

Producer or importer — paragraph 46(1)(a)

57 (1) A feedstock referred to in paragraph 46(1)(a) is not eligible unless

(a) the registered creator ensures that any person who produces a low-carbon-intensity fuel using the feedstock retains the following records:
- (i) delivery records, contracts and invoices with respect to each quantity of the feedstock that is brought to any of their facilities,
- (ii) sales records for all low-carbon-intensity fuel, other than co-processed low-carbon-intensity fuel, that was produced using all or any portion of a quantity of the feedstock, and
- (iii) records for all co-processed low-carbon-intensity fuel that demonstrate that it was produced using all or any portion of a quantity of eligible feedstock; and
(b) the registered creator who imports into Canada a quantity of a low-carbon-intensity fuel produced using the feedstock retains the following records with respect the quantity of low-carbon-intensity fuel:
- (i) delivery records, contracts and invoices, and
- (ii) sales records.

Eligibility — paragraph 46(1)(b) or (c)

(2) A feedstock referred to in paragraph 46(1)(b) or (c) is not eligible unless

(a) declarations are made by the following persons in accordance with any of subsections 58(1) to (4) at least once every year:
- (i) every person who possesses all or any portion of a quantity of the feedstock when it is mixed with another quantity of any feedstock,
- (ii) every person who possesses all or any portion of a quantity of the feedstock when it is processed,
- (iii) every person who possesses all or any portion of a quantity of the feedstock when it is divided into multiple portions,
- (iv) the person who is responsible for obtaining all or any portion of a quantity of the feedstock from its first point of use or disposal, in the case of a feedstock referred to in paragraph 46(1)(b), and
- (v) the person who is responsible for harvesting all or any portion of a quantity of the feedstock, in the case of a feedstock referred to in paragraph 46(1)(c);
(b) the registered creator or foreign supplier ensures that any person who harvests, mixes, processes, divides or obtains all or any portion of a quantity of the feedstock retains
- (i) the declaration that they made under paragraph (a),
- (ii) a copy of the declaration made under paragraph (a), if any, by the person who possessed that quantity immediately before they did, and
- (iii) records that establish the quantity of the feedstock that enters and is removed from the site where it is harvested, mixed, processed, divided or obtained;
(c) the registered creator or foreign supplier retains records in accordance with subsection 59(1);
(d) the registered creator who imports into Canada a low-carbon-intensity fuel that was produced using the feedstock retains records in accordance with subsection 59(2); and
(e) the registered creator or foreign supplier has a methodology in place to determine whether, each time a quantity of the feedstock is removed from the site where it is harvested, mixed, processed, divided or obtained, the quantity that is removed from the site is less than or equal to the quantity determined by the formula set out in subsection 47(1).

Declaration by harvester

58 (1) A declaration made by a person referred to in subparagraph 57(2)(a)(v) must contain the following information:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) if an authorized agent is making the declaration on behalf of the person, the name, civic address, postal address, telephone number and, if any, email address of the authorized agent;
(c) the GPS coordinates to the fifth decimal place and, if any, civic address of the site where the feedstock that is the subject of the declaration was harvested;
(d) an indication of whether any part of that site is on land referred to in subsection 48(1) and, if so, confirmation that they have a record of the Minister’s authorization under subsection 48(2);
(e) if the feedstock is sold, the name and civic and postal address of the person to whom it is sold;
(f) the type of the feedstock;
(g) the quantity of the feedstock that is sold, expressed in kilograms or cubic metres, as applicable;
(h) a confirmation that the requirements set out in section 48 are met with respect to the feedstock or that the feedstock is the subject of an exemption granted under paragraph 55(1)(a);
(i) a confirmation that the requirements set out in section 49 are met with respect to the feedstock or that feedstock is the subject of an exemption granted under paragraph 55(1)(b);
(j) if the feedstock is a crop, a confirmation that it was not harvested on land described in section 51 or is the subject of an exemption granted under subsection 53(1) or 54(1);
(k) if the feedstock is derived from forest biomass, a confirmation that
- (i) it was harvested in accordance with the requirements set out in paragraph 52(c)(i) or is the subject of an exemption granted under paragraph 55(1)(c),
- (ii) it was harvested in accordance with the requirements set out in subparagraph 52(c)(ii) or is the subject of an exemption granted under paragraph 55(1)(d),
- (iii) it was harvested in accordance with the requirements set out in subparagraph 52(c)(iii) as it relates to soil or is the subject of an exemption granted under paragraph 55(1)(e),
- (iv) it was harvested in accordance with the requirements set out in subparagraph 52(c)(iii) as it relates to surface and ground water resources or is the subject of an exemption granted under paragraph 55(1)(f),
- (v) it was harvested in accordance with the requirements set out in subparagraph 52(c)(iii) as it relates to biodiversity or is the subject of an exemption granted under paragraph 55(1)(g), and
- (vi) it was harvested in accordance with the requirements set out in subparagraph 52(c)(iv) or is the subject of an exemption granted under paragraph 55(1)(h);
(l) if the feedstock is a crop, a confirmation that it meets the requirements set out in section 50;
(m) the unique identifier for the declaration that they use for their internal accounting purposes;
(n) the date on which the declaration is made; and
(o) the signature of the person or their authorized agent.

Certification

(2) If a feedstock referred to in paragraph 46(1)(c) is certified by a certification body in accordance with section 61, the declaration must be accompanied by a copy of the certificate and contain

(a) an indication of the requirements set out in sections 48 to 52 that the certified feedstock meets;
(b) the name of the certification scheme under which it was certified;
(c) the name of the certification body that certified the feedstock; and
(d) the day referred to in paragraph 70(2)(c) or (d) on which the certificate is expected to cease to be valid.

Declaration — foreign supplier

(3) A declaration made by a foreign supplier must contain the following information:

(a) the name, civic address, postal address, telephone number and, if any, email address of the foreign supplier;
(b) if an authorized agent is making the declaration on behalf of the foreign supplier, the name, civic address, postal address, telephone number and, if any, email address of the authorized agent;
(c) the GPS coordinates to the fifth decimal place and, if any, civic address of the site where the mixing, processing or division, as the case may be, of the quantity of the feedstock was carried out or of the site where the quantity was obtained;
(d) the type of the feedstock that is used;
(e) the quantity of the feedstock that is used at the site referred to in paragraph (c) by the person mixing, processing, dividing or obtaining feedstock to produce low-carbon-intensity fuel, expressed in kilograms or cubic metres, as applicable;
(f) a confirmation that the requirements set out in subsection 47(2) were met with respect to any portion of the quantity of feedstock that was used to produce low-carbon-intensity fuel and that the foreign supplier has retained evidence of the compliance at the site where the low-carbon-intensity fuel was produced;
(g) a confirmation that the requirements set out in sections 48 to 52 are met with respect to the feedstock except if it is exempted under any of sections 53 to 55;
(h) the total quantity of low-carbon-intensity fuel that the foreign supplier produced outside Canada and that they sold for import into Canada;
(i) a confirmation that the foreign supplier is in compliance with subsection 59(1);
(j) in the case of a person who is the producer of the low-carbon-intensity fuel made using the feedstock, any alphanumeric identifier assigned to the fuel’s carbon intensity;
(k) the unique identifier for the declaration that the foreign supplier uses for their internal accounting purposes;
(l) the date on which the declaration is made; and
(m) the signature of the foreign supplier or their authorized agent.

Declaration by other person

(4) A declaration made by a person referred to in any of subparagraphs 57(2)(a)(i) to (iv), other than a registered creator or foreign supplier, must contain the following information:

(a) the name, civic address, postal address, telephone number and, if any, email address of the person;
(b) if an authorized agent is making the declaration on behalf of the person, the name, civic address, postal address, telephone number and, if any, email address of the authorized agent;
(c) the GPS coordinates to the fifth decimal place and, if any, civic address of the site where the mixing, processing or division, as the case may be, of the quantity of the feedstock was carried out or of the site where the quantity was obtained;
(d) if the feedstock is sold, the name and civic and postal address of the person to whom it was sold;
(e) the type of the feedstock;
(f) the quantity of the feedstock that is removed from the site referred to in paragraph (c), expressed in kilograms or cubic metres, as applicable;
(g) a confirmation that, when the feedstock was removed from that site or was mixed, divided or obtained at that site, the requirements set out in subsection 47(1) were met with respect to the feedstock and that the person who mixed, divided or obtained the feedstock has retained evidence of compliance at that site;
(h) a confirmation that the requirements set out in sections 48 to 52 are met with respect to the feedstock except if it is exempted under any of sections 53 to 55;;
(i) in the case of a declaration referred to in subparagraph 57(2)(a)(iv) with respect to a quantity of a feedstock that is referred to in any of subparagraphs 46(1)(b)(ii) to (vi), a confirmation that the feedstock meets the requirements set out in section 50;
(j) in the case of a declaration referred to in subparagraph 57(2)(a)(iv), a confirmation that they have retained at the site referred to in paragraph (c), for each quantity of feedstock referred to in any of subparagraphs 46(1)(b)(iv) to (vi), delivery records, contracts and invoices that describe the location where that feedstock was first used;
(k) the unique identifier for the declaration that they use for their internal accounting purposes;
(l) the date on which the declaration is made; and
(m) the signature of the person or their authorized representative.

Unique identifier

(5) The unique identifier referred to in paragraphs (1)(m), (3)(k) and (4)(k) must be unique to each declaration and indicate the lot number of the feedstock to which it applies. It must be used in all records related to material balances at the site to which it applies.

Producer records

59 (1) A person who produces a quantity of low-carbon-intensity fuel using a feedstock referred to in paragraph 46(1)(b) or (c) must retain the following:

(a) delivery records, contracts and invoices with respect to each quantity of the feedstock that is brought to any of their facilities;
(b) the sales records for all low-carbon-intensity fuel, other than co-processed low-carbon-intensity fuel, that was produced using all or any portion of a quantity of the feedstock;
(c) records for all co-processed low-carbon-intensity fuel that demonstrate that it was produced using all or any portion of a quantity of eligible feedstock;
(d) a copy of the declaration made under paragraph 57(2)(a) by each person who possessed all or any portion of a quantity of the feedstock immediately before them;
(e) any information used to make the calculations referred to in subsections 45(1) and 47(2), the evidence that supports that information and the results of those calculations; and
(f) a copy of the certificate referred to in subsection 70(1), if any, that is issued with respect to the feedstock.

Importer records

(2) A person who imports into Canada a quantity of low-carbon-intensity fuel must retain the following:

(a) delivery records, contracts and invoices with respect to the quantity of low-carbon-intensity fuel;
(b) the sales records for that quantity of low-carbon-intensity fuel; and
(c) if the low-carbon-intensity fuel is produced using an eligible feedstock referred to in paragraph 46(1)(b) or (c), a copy of the declaration made under subsection 58(3) by the foreign supplier of the fuel.

Non-application

60 Sections 48, 49, 51 to 59 do not apply before January 1, 2024.

Certification

61 An eligible feedstock referred to in paragraph 46(1)(c) may be certified only by a certification body that is eligible under section 63 and that conducts the certification in accordance with sections 64 to 74 and under a certification scheme that is approved by the Minister under section 62.

Approval by Minister

62 (1) The Minister may approve a certification scheme if the following conditions are met:

(a) the Minister is satisfied that the applicable requirements set out in sections 48 to 52 will be met in respect of all of the feedstock certified using the certification scheme’s procedures;
(b) the certification scheme is developed and maintained by a person who is the scheme owner and that person
- (i) has structures in place for operating and managing the certification scheme,
- (ii) creates, maintains and has control of adequate documentation for the operation, maintenance and improvement of the certification scheme,
- (iii) has measures in place to respond to complaints with respect to the certification scheme,
- (iv) has measures in place to retain records securely for 10 years,
- (v) creates, maintains and has control of an information management system,
- (vi) protects the confidentiality of information provided by the parties involved in the certification scheme, and
- (vii) has developed requirements that comply with sections 63 to 67 for certification bodies, as well as requirements regarding the specific competencies required of certification bodies and the way in which certification bodies are to demonstrate their compliance with those requirements;
(c) in the case where the feedstock is harvested in accordance with a forest management plan referred to in section 52, the certification scheme provides that the management plan must be assessed by a specialist in forestry;
(d) a plan is in place to review the certification scheme at planned intervals;
(e) procedures are in place to review the certification scheme when
- (i) there is a significant change to the certification scheme, or
- (ii) a complaint is received that indicates that a review is necessary;
(f) procedures, including for considering comments from stakeholders, are in place to ensure that the integrity, exhaustiveness and effectiveness of the certification scheme is verified during reviews;
(g) the certification scheme includes procedures to ensure that the following are publicly available:
- (i) the most recent versions of the certification scheme and documentation for the scheme that are in the common language of each region to which the certification scheme applies,
- (ii) a list, current to the day, of the feedstock harvesters that are certified under the certification scheme,
- (iii) a list of certification bodies that are authorized to conduct audits under the certification scheme,
- (iv) a list of certification bodies that were previously authorized to conduct audits under the certification scheme, including an indication as to whether those bodies are no longer authorized on a permanent or temporary basis, and
- (v) contact information for the scheme owner;
(h) the certification scheme provides that a list of persons who have not complied with the certification scheme must be submitted, on request, to the Minister;
(i) in the case of a certification scheme that permits a group of producers to be certified together, the certification scheme requires that
- (i) the producers in the group use similar production systems and information management systems and harvest feedstock of the same type and in areas that are near each other and have similar climatic conditions, and
- (ii) there be clear conditions and procedures for a producer to join the group;
(j) the certification scheme sets out the measures that a certification body must take if a feedstock producer fails to comply with the certification scheme, including
- (i) the denial of an application for certification or the revocation of a certificate in accordance with section 71, or the denial of an application for certification or the suspension of a certificate in accordance with section 72, in the circumstances indicated by the certification scheme, and
- (ii) the establishment of procedures in respect of corrective actions that must be taken with respect to the circumstances of non-conformity referred to in section 73;
(k) the certification scheme includes conditions on the ways in which a feedstock harvester may use certificates issued under it; and
(l) the certification scheme owner monitors the use of certificates issued under the certification scheme.

End of approval

(2) A certification scheme ceases to be approved on the earlier of

(a) sixty days after the day on which there is a change to the scope of the scheme, unless the scheme owner notifies the Minister of the change and the Minister determines that, despite the change, the scheme continues to meet the conditions for approval,
(b) sixty days after the day on which there is a change to any procedure set out in the scheme on which the Minister’s approval was based, unless the scheme owner notifies the Minister of the change and the Minister determines that, despite the change, the scheme continues to meet the conditions for approval,
(c) the first anniversary of the day on which the scheme was most recently approved by the Minister unless, before that anniversary, the scheme owner submits a report that contains the information referred to in Schedule 5 to the Minister concerning the operation of the certification scheme during the preceding year,
(d) the first anniversary of the day on which the scheme owner most recently submitted a report that contains the information referred to in Schedule 5 to the Minister concerning the operation of the certification scheme within the preceding year, and
(e) the fifth anniversary of the day on which the scheme was most recently approved by the Minister.

Eligibility conditions for accreditation

63 (1) A person is eligible to be accredited as a certification body by the Standards Council of Canada, the American National Standards Institute (ANSI) National Accreditation Board or a designated accreditation body if the person

(a) meets the applicable requirements set out in ISO/IEC Standard 17065 or, in the case of a certification body that assesses a forest management plan referred to in section 52, meets the applicable requirements set out in ISO/IEC Standard 17021-1; and
(b) demonstrates that they comply with the competency requirements of the certification scheme for which they are to be accredited.

Designation of accreditation body

(2) The Minister may designate an accreditation body as a designated accreditation body if it is a member of the International Accreditation Forum or an equivalent body and meets the requirements set out in ISO/IEC Standard 17011.

Suspended or revoked accreditation

(3) The certification of a feedstock must not be conducted by a certification body whose accreditation is suspended or revoked.

No outsourcing

64 It is not permitted to outsource any of the activities that are carried out as part of the certification of a feedstock.

Consecutive certifications

65 The certification of a feedstock must be conducted by a team that does not include any individual who has contributed to the certification of the feedstock for five consecutive compliance periods, unless three compliance periods have elapsed since the most recent of those consecutive compliance periods.

Certification team — members

66 (1) A certification team must consist only of members who meet the requirements of clause 7 of ISO Standard 19011 and must include the following individuals:

(a) a team leader who is competent with respect to the feedstock being certified;
(b) if it is relevant to the feedstock being certified, at least one specialist in forestry or agriculture, as the case may be, who is recognized as a forestry engineer, professional forester, agricultural engineer or agrologist by
- (i) a Canadian professional association, in the case of forestry or agriculture that occurs in Canada, and
- (ii) a relevant national authority of the country in which the forestry or agriculture occurs, in any other case; and
(c) if it is relevant to the feedstock being certified, at least one specialist in biodiversity who holds a bachelor’s degree in biology, natural sciences or environmental sciences granted by a Canadian university, or an equivalent degree granted by a university outside Canada.

Person responsible for making decision

(2) The person responsible for making a certification decision must have, at a minimum, the same competencies as those set out for an audit team leader in subclause 7.2.3.4 of ISO Standard 19011.

Applicable standards for certification

67 (1) A certification body must conduct a certification in accordance with the Methods for Verification and Certification and with

(a) ISO/IEC Standard 17065 or, in the case where the feedstock is harvested in accordance with a forest management plan referred to in section 52, ISO/IEC Standard 17021-1; and
(b) ISO Standard 19011.

Interpretation of ISO/IEC Standard 17065

(2) For the purposes of ISO/IEC Standard 17065

(a) a reference to a “product requirement” in subclause 3.8 of that Standard is to be read as a reference to the requirements set out in sections 48 to 52 of these Regulations; and
(b) a reference to a “location” in that Standard is to be read as a reference to a farm, forest or any other place where the feedstock is harvested.

Interpretation of ISO/IEC Standard 17021-1

(3) For the purposes of ISO/IEC Standard 17021-1,

(a) a reference to an “audit criteria” in subclause 9.2.1 of that Standard is to be read as a reference to the requirements set out in section 52 of these Regulations; and
(b) a reference to a “site” in that Standard is to be read as a reference to a farm, forest or any other place where the feedstock is harvested.

Annual surveillance audit

68 The certification of a feedstock conducted by a certification body must include an annual surveillance audit to ensure that the feedstock is harvested in accordance with the requirements of sections 48 to 52.

Site visits

69 (1) The certification of a feedstock conducted by a certification body must include a site visit if it is the first certification of the feedstock or if, in the case of any subsequent audit, the risk of any non-conformity with the certification scheme is high.

Remote audits

(2) A site visit is not required during the conduct of a surveillance audit if

(a) the collection of data may be done remotely in a manner that reduces, to a reasonable level, the risk of failing to detect any non-conformity with the certification scheme; or
(b) the risk of any non-conformity with the certification scheme is low.

Unambiguous identification

70 (1) A certificate issued by a certification body must unambiguously identify the feedstock to which it applies.

End of certification

(2) The certificate ceases to be valid on the earlier of

(a) the day on which a certification body, on the basis of an audit it conducted, is no longer satisfied that the applicable requirements set out in sections 48 to 52 are met,
(b) the day that is the first anniversary of the day on which the most recent audit was conducted by the certification body,
(c) the day that is the fifth anniversary of the day on which the certificate was issued, and
(d) the day specified by the certification scheme under which the certification body conducts the certification.

Denial or revocation

71 (1) If any of the following circumstances occur with respect to a feedstock, an application for the certification of the feedstock must be denied or, in the case where a certificate has been issued for the feedstock, the certificate must be revoked:

(a) the applicable requirements set out in sections 48 to 52 are not met with respect to the feedstock and the situation cannot be rectified by corrective action;
(b) the producer of the feedstock fails to comply with the certification scheme and the situation cannot be rectified by taking corrective action;
(c) the producer of the feedstock fails to comply with the certification scheme in a manner that undermines the integrity of the certification scheme.

New application for certification

(2) The producer of a feedstock in respect of which an application for certification has been denied, or a certificate has been revoked, under subsection (1) may submit a new application for certification of the feedstock after the end of the period specified by the certification scheme.

Denial or suspension of certification

72 (1) If any of the following circumstances occur with respect to a feedstock, an application for the certification of the feedstock must be denied or, in the case where a certificate has been issued for the feedstock, the certificate must be suspended:

(a) the applicable requirements set out in sections 48 to 52 are not met with respect to the feedstock and the situation can be rectified by taking corrective action;
(b) the producer of the feedstock repeatedly fails to comply with the certification scheme, including in the following cases:
- (i) more than 5% of the evidence that is provided to the certification body and included in a representative sample contains gaps or errors,
- (ii) the producer fails to disclose their participation in other certification schemes during the certification process, or
- (iii) the producer fails to provide the certification body with any relevant information.

Duration of suspension

(2) The suspension of the certificate begins on the day on which the producer of the feedstock is notified of the suspension and ends after 90 days.

Revocation

(3) The certificate must be revoked at the end of the 90-day suspension period if the producer of the feedstock has not taken corrective action with respect to the situation that resulted in the suspension.

Other circumstances of non-conformity

73 (1) A certification scheme may, if a producer of a feedstock has not complied with the scheme in circumstances other than those referred to in subsections 71(1) and 72(1), provide for a period during which the producer must take corrective action with respect to the circumstances of non-conformity.

Time limit for corrective action

(2) The period within which the producer must take the corrective action ends on the earlier of

(a) the day on which the next surveillance audit of the feedstock is to be conducted,
(b) the day on which the certification is renewed,
(c) the day that is 12 months after the day on which the producer of the feedstock is notified of the non-conformity by the certification body, and
(d) the day specified by the certification scheme.

Prior certification under another certification scheme

74 An application for the certification of a feedstock must contain the following information:

(a) a statement as to whether the feedstock has, in the previous five years, been the subject of a certification under another certification scheme;
(b) all relevant information relating to a certification of the feedstock under another certification scheme, including audit reports and any decisions to suspend or revoke the certification during the previous five years, as well as the reasons for any suspension or revocation; and
(c) a statement specifying the reasons for which any producer of the feedstock withdrew from another certification scheme before the first surveillance audit.

Determination of Carbon Intensity

Low-carbon-intensity fuel

75 (1) The carbon intensity of a low-carbon-intensity fuel, other than hydrogen produced from a fossil fuel, and the carbon intensity of a material input that is a renewable natural gas, biogas, renewable propane or hydrogen, other than hydrogen produced from a fossil fuel, is, at the election of the registered creator or foreign supplier,

(a) the default carbon intensity referred to in section 1 of Schedule 6; or
(b) determined by the formula

CI_f + CI_p + CI_cl + CI_e + CI_td + CI_c: where
CI_f: is the quantity of CO₂e emissions set out in section 2 of Schedule 6 that represents the quantity of CO₂e that is associated with the extraction or production, as the case may be, of the feedstock from which the fuel or material input is produced, per megajoule of energy produced,
CI_p: is the quantity of CO₂e emissions set out in section 3 of Schedule 6 that represents the quantity of CO₂e that is released during the production of the fuel or material input from the feedstock, the transportation of the feedstock and intermediary products used to produce the fuel or material input and the distribution of the fuel or material input to end users, per megajoule of energy produced,
CI_cl: is the quantity of CO₂e emissions set out in section 4 of Schedule 6 that represents the quantity of CO₂e that is released during the compression or liquefaction of the fuel or material input, per megajoule of energy produced,
CI_e: is the quantity of CO₂e emissions set out in section 5 of Schedule 6 that represents the additional quantity of CO₂e that is associated with the production of electricity used during the production of the fuel or material input, per megajoule of energy produced,
CI_td: is the quantity of CO₂e emissions set out in section 6 of Schedule 6 that represents the additional quantity of CO₂e that is released during the transportation of the feedstock and intermediary products used to produce the fuel or material input and the distribution of the fuel or material input to end users, per megajoule of energy produced, in the case of a total transportation distance of no less than 1500 km, and
CI_c: is the quantity of CO₂e emissions set out in section 7 of Schedule 6 that represents the quantity of CO₂e that is released during the combustion of the fuel or the use of the material input, per megajoule of energy produced.

Use limited to 12 months

(2) The default carbon intensity referred to in paragraph (1)(a) must not be used to create compliance credits for a period of more than 12 consecutive months or more than 12 months during two consecutive compliance periods, unless the Minister, at the written request of the registered creator, approves the use of that carbon intensity for any longer period specified by the Minister.

Use pending approval

(3) However, in the case of an application under subsection 80(1) for the approval of a carbon intensity determined in accordance with paragraph (1)(b) or subsection 76(1), the applicant may use the default carbon intensity referred to in paragraph (1)(a) to create compliance credits during the period beginning on the day on which the application is made and ending on the day on which the carbon intensity is approved under subsection 85(1), even if that period is longer than 12 consecutive months.

Input data for less than three months

(4) A registered creator or foreign supplier may elect to use the carbon intensity referred to in paragraph (1)(b) if they have input data, for a period of less than three consecutive months, derived from the activities referred to in the definition carbon intensity in subsection 1(1) that are carried out over the life cycle of the fuel or the life cycle of the material input, as the case may be.

Use limited to three compliance periods

(5) The carbon intensity referred to in paragraph (1)(b) must not be used to create credits other than for a period of no more than three consecutive compliance periods.

Fossil fuels

(6) For the purposes of subsections 98(2), 99(3) and (4) and 104(2), the carbon intensity of a fuel that is hydrogen, propane, natural gas, liquefied natural gas and compressed natural gas is, at the election of the registered creator, the amount set out in

(a) section 8 of Schedule 6; or
(b) the Specifications for Fuel LCA Model CI Calculations.

Electricity

(7) The carbon intensity of electricity for a province in which a charging station is located is, at the election of the registered creator, the amount set out for that province in

(a) section 9 of Schedule 6; or
(b) the Specifications for Fuel LCA Model CI Calculations.

Fuel LCA Model — registered creator or foreign supplier

76 (1) A registered creator or foreign supplier may elect to determine the carbon intensity of a low-carbon-intensity fuel, or the carbon intensity of a material input that is a renewable natural gas, biogas, renewable propane or hydrogen, using the Fuel LCA Model in accordance with the option set out in either paragraph (3)(a) or (b), if they have input data, for a period of 24 consecutive months during the period of 30 months that immediately precedes the day on which they make the election, derived from the activities referred to in the definition carbon intensity in subsection 1(1) that are carried out over the life cycle of the fuel or material input, as the case may be.

Carbon-intensity contributor

(2) A carbon-intensity contributor may elect to determine the carbon intensity of a low-carbon-intensity fuel or material input that is a renewable natural gas, biogas, renewable propane or hydrogen in accordance with the option set out in either paragraph (3)(a) or (b), if they have input data, for a period of 24 consecutive months during the period of 30 months that immediately precedes the day on which they make the election, derived from the activities referred to in the definition carbon intensity in subsection 1(1) that are carried out over the life cycle of the fuel or material input, as the case may be.

Options on election

(3) The carbon intensity may be determined based on the input data referred to in subsection (1) or (2) in accordance with either of the following options:

(a) an existing pathway from the Fuel LCA Model; or
(b) a new pathway created by the registered creator, carbon-intensity contributor or foreign supplier from the Fuel LCA Model, in the case where
- (i) the fuel or material input is not indicated in the Fuel LCA Model,
- (ii) the feedstock used to produce the fuel or material input is not indicated in the Fuel LCA Model, or
- (iii) the criteria provided in the Specifications for Fuel LCA Model CI Calculations for creating a new pathway are met.

Fuel LCA Model — co-processed low-carbon-intensity fuel

77 A registered creator or foreign supplier must determine the carbon intensity of a co-processed low-carbon-intensity fuel using the Fuel LCA Model in accordance with the applicable specific emission-reduction quantification method established under subsection 32(1) and either of the following options:

(a) an existing pathway from the Fuel LCA Model; or
(b) a new pathway created by the registered creator or foreign supplier from the Fuel LCA Model, in the case where
- (i) the fuel is not indicated in the Fuel LCA Model,
- (ii) the feedstock used to produce the fuel is not indicated in the Fuel LCA Model, or
- (iii) the criteria provided in the Specifications for Fuel LCA Model CI Calculations for creating a new pathway are met.

Compressed and liquefied gases

78 (1) Instead of determining the carbon intensity of propane, liquefied natural gas or compressed natural gas in accordance with subsection 75(6), a registered creator may elect to make that determination using the Fuel LCA Model in accordance with the option set out in either paragraph (3)(a) or (b), if they have input data, for a period of 24 consecutive months during the period of 30 months that immediately precedes the day on which they make the election, respecting the operation of a fuelling station or the liquefaction process for propane, renewable propane, co-processed low-carbon intensity propane, compressed natural gas, renewable compressed natural gas, liquefied natural gas or renewable liquefied natural gas.

Renewable fuels

(2) In the case of renewable propane, co-processed low-carbon-intensity propane, renewable compressed natural gas and renewable liquefied natural gas, the determination is to be made as if

(a) the renewable propane or co-processed low-carbon-intensity propane were propane;
(b) the renewable compressed natural gas were compressed natural gas; or
(c) the liquefied renewable natural gas were liquefied natural gas.

Options on election

(3) The carbon intensity may be determined based on the input data referred to in subsection (1) in accordance with either of the following options:

(a) an existing pathway from the Fuel LCA Model; or
(b) a new pathway created by the registered creator or foreign supplier from the Fuel LCA Model, in the case where
- (i) the fuel is not indicated in the Fuel LCA Model,
- (ii) the feedstock used to produce the fuel is not indicated in the Fuel LCA Model, or
- (iii) the criteria provided in the Specifications for Fuel LCA Model CI Calculations for creating a new pathway are met.

Electricity

79 (1) A registered creator or carbon-intensity contributor may elect to determine, in accordance with subsection (3), the carbon intensity of the electricity supplied to electric vehicles by a charging station that is not intended primarily for use by the occupants of a private dwelling-place if they have input data respecting the source and quantity of that electricity for a period of 24 consecutive months during the period of 30 months that immediately precedes the day on which they make the election.

Electricity — fuelling station or facility

(2) A registered creator or carbon-intensity contributor may elect to determine, in accordance with subsection (3), the carbon intensity of the electricity supplied to a fuelling station or facility if they have input data respecting the source and quantity of that electricity for a period of 24 consecutive months during the period of 30 months that immediately precedes the day on which they make the election.

Options on election

(3) The carbon intensity may be determined based on the input data referred to in subsection (1) or (2) in accordance with either of the following options:

(a) an existing pathway from the Fuel LCA Model; or
(b) a new pathway created by the registered creator or carbon-intensity contributor from the Fuel LCA Model, in the case where the source of the electricity is not indicated in the Fuel LCA Model or where the criteria indicated in the Specifications for Fuel LCA Model CI Calculations for creating a new pathway are met.

Application for approval of carbon intensity

80 (1) A registered creator, carbon-intensity contributor or foreign supplier may apply to the Minister for the approval of a carbon intensity determined in accordance with paragraph 75(1)(b) or any of sections 76 to 79, as the case may be.

Carbon-intensity additional value

(2) In the case of an application for the approval of a carbon intensity determined in accordance with section 76, 78 or 79, the registered creator, carbon-intensity contributor or foreign supplier may add an additional value to that carbon intensity, in which case the carbon intensity that is the subject of the application for approval would be the sum of the additional value and the carbon intensity determined using the Fuel LCA Model.

Imported fuel

(3) Despite subsection (1), in the case of a fuel produced outside Canada and imported into Canada in respect of which compliance credits are created under paragraph 19(1)(b) or 20(b) or when a CO₂e-emission-reduction project described in paragraph 30(d) is carried out, only the foreign supplier of the fuel may make the application for the approval of the carbon intensity.

Distinct application — each feedstock

(4) A distinct application for the approval of a carbon intensity is required for each type of feedstock that is used to produce a low-carbon-intensity fuel or a material input that is renewable natural gas, biogas, renewable propane or hydrogen, including in the case where two or more types of feedstock are used simultaneously to produce the low-carbon-intensity fuel or the material input.

Pathway approval

81 (1) Before making an application under subsection 80(1) for the approval of a carbon intensity based on a new pathway referred to in paragraph 76(3)(b), 77(b), 78(3)(b) or 79(3)(b), the registered creator, carbon-intensity contributor or foreign supplier must apply to the Minister for the approval of the new pathway.

Application

(2) The application for the approval of a new pathway must include the information referred to in Schedule 7.

Approval

(3) The Minister must approve the new pathway if the Minister is satisfied that the pathway is based on

(a) a plan to collect verifiable data and results;
(b) calculations that do not contain any error that attains any of the quantitative materiality thresholds referred to in paragraph 150(a);
(c) unit processes, modelling parameters, background data sets and a methodology that are appropriate for the pathway; and
(d) a methodology that is consistent with ISO Standard 14040, ISO Standard 14044 and the Specifications for Fuel LCA Model CI Calculations.

Unique alphanumeric identifier

(4) When the Minister approves the new pathway, the Minister must assign a unique alphanumeric identifier to it.

Information to be provided

82 (1) An application made under section 80 in respect of a carbon intensity determined in accordance with paragraph 75(1)(b) or section 76 or 77 must contain the information referred to in section 1 of Schedule 8.

Additional information — paragraph 75(1)(b)

(2) In the case of a carbon intensity determined in accordance with paragraph 75(1)(b), the application must also contain the information referred to in section 2 of Schedule 8.

Additional information — section 76

(3) In the case of a carbon intensity determined in accordance with section 76, the application must also contain the information referred to in sections 3 and 6 of Schedule 8, as well as any information specified in any applicable emission-reduction quantification method established under subsection 31(1) or 32(1).

Additional information — section 77

(4) In the case of a carbon intensity determined in accordance with section 77, the application must also contain the information referred to in sections 3 and 6 of Schedule 8, as well as any information specified in any applicable specific emission-reduction quantification method established under subsection 32(1).

Information to be provided — section 78

83 In the case of a carbon intensity determined in accordance with section 78, an application made under section 80 must contain the information referred to in sections 4 and 6 of Schedule 8.

Information to be provided — section 79

84 In the case of a carbon intensity determined in accordance with section 79, an application made under section 80 must contain the information referred to in sections 5 and 6 of Schedule 8.

Approval

85 (1) The Minister must approve a carbon intensity for which an application for approval is made under section 80 if the Minister is satisfied that the determination of the carbon intensity is based on

(a) data and results that are verifiable;
(b) calculations that do not contain any error that attains any of the quantitative materiality thresholds referred to in paragraph 150(a);
(c) unit processes, modelling parameters, background data sets and a methodology that are appropriate for that determination and do not result in an underestimation of the carbon intensity;
(d) in the case of a determination made in accordance with section 76 or 77, a methodology that is consistent with ISO Standard 14040, ISO Standard 14044 and the Specifications for Fuel LCA Model CI Calculations; and
(e) with respect to an application referred to in section 130, an unqualified opinion issued in accordance with paragraph 154(a) or a qualified opinion issued in accordance with paragraph 154(b).

Unique alphanumeric identifier

(2) When the Minister approves the carbon intensity, the Minister must assign it a unique alphanumeric identifier.

End of validity

86 (1) The approved carbon intensity of a low-carbon-intensity fuel or material input ceases to be valid if a change is made to the extraction or production processes for the feedstock used to produce the fuel or material input or the production processes and that change is not consistent with the emission factors, input data, background data sets and methodology that were used to determine the carbon intensity and would result in,

(a) in the case where the carbon intensity was determined in accordance with paragraph 75(1)(b), production processes that are different than those used to determine the approved carbon intensity of the fuel or material input;
(b) in the case where the carbon intensity was determined in accordance with section 76, an actual carbon intensity of the fuel or material input — as specified in the carbon-intensity-pathway report referred to in subsection 123(1) — that is greater than the approved carbon intensity by at least
- (i) 1 gCO₂e/MJ, if the absolute value of the approved carbon intensity is less than 20 gCO₂e/MJ,
- (ii) 5%, if the absolute value of the approved carbon intensity is between 20 and 100 gCO₂e/MJ, and
- (iii) 5 gCO₂e/MJ, if the absolute value of the approved carbon intensity is greater than 100 gCO₂e/MJ; and
(c) in the case where the carbon intensity was approved for a CO₂e-emission-reduction project described in paragraph 30(d), fuel production processes or conditions that are different than those indicated in the application made under subsection 80(1) for the approval of the carbon intensity.

Non-compliance with section 123

(2) The approved carbon intensity of a fuel or material input ceases to be valid if the registered creator, carbon-intensity contributor or foreign supplier who made the application for approval under subsection 80(1) fails to comply with the requirements set out in section 123.

Non-compliance with section 124

(3) The approved carbon intensity of a gaseous or liquid low-carbon-intensity fuel that was produced using a quantity of an eligible feedstock referred to in paragraph 46(1)(b) or (c) ceases to be valid if the registered creator or foreign supplier who made the application for approval under subsection 80(1) fails to comply with the requirements set out in section 124.

Non-compliance with specific quantification method

(4) The approved carbon intensity of a co-processed low-carbon-intensity fuel ceases to be valid if a registered creator or foreign supplier referred to in subsection 80(1) fails to comply with the applicable specific emission-reduction quantification method established under subsection 32(1).

Non-compliance with record requirements

(5) The approved carbon intensity of a low-carbon-intensity fuel or material input may be invalidated by the Minister if the registered creator, carbon-intensity contributor or foreign supplier who made the application for approval under subsection 80(1) fails to comply with any of the requirements set out in sections 166 and 168 in relation to the approved carbon intensity.

End of validity — certain gases

(6) The approved carbon intensity of propane, liquefied natural gas or compressed natural gas determined in accordance with section 78 ceases to be valid if a change is made to the compression or liquefaction process for the fuel and that change is not consistent with the emission factors, input data, background data sets and methodology that were used to determine the carbon intensity and would result in an actual carbon intensity of the fuel — as specified in the carbon-intensity-pathway report referred to in subsection 123(1) — that is greater than the approved carbon intensity by at least

(a) 1 gCO₂e/MJ, if the absolute value of the approved carbon intensity is less than 20 gCO₂e/MJ;
(b) 5%, if the absolute value of the approved carbon intensity is between 20 and 100 gCO₂e/MJ; and
(c) 5 gCO₂e/MJ, if the absolute value of the approved carbon intensity is greater than 100 gCO₂e/MJ.

End of validity — electricity

(7) The approved carbon intensity of electricity determined in accordance with section 79 ceases to be valid if a change is made to the source and quantity of electricity supplied to electric vehicles or facilities and that change would result in an actual carbon intensity of the electricity — as specified in the carbon-intensity-pathway report referred to in subsection 123(1) — that is greater than the approved carbon intensity by at least

(a) 1 gCO₂e/MJ, if the absolute value of the approved carbon intensity is less than 20 gCO₂e/MJ;
(b) 5%, if the absolute value of the approved carbon intensity is between 20 and 100 gCO₂e/MJ; and
(c) 5 gCO₂e/MJ, if the absolute value of the approved carbon intensity is greater than 100 gCO₂e/MJ.

Transferred carbon intensity

(8) The approved carbon intensity of a fuel or material input ceases to be valid if the registered creator, carbon-intensity contributor or foreign supplier who made the application for the approval of that carbon intensity under subsection 80(1) has determined it by using a carbon intensity that ceases to be valid under any of subsections (1) to (7).

End of validity — December 31, 2025

(9) A carbon intensity determined in accordance with any of sections 76 to 79 that was approved by the Minister before July 1, 2024 ceases to be valid on December 31, 2025. The registered creator, carbon-intensity contributor or foreign supplier may, on or after July 1, 2024, submit a new application to the Minister for the approval of the carbon intensity under subsection 80(1).

New application

87 (1) A registered creator or foreign supplier may apply to replace a carbon intensity approved by the Minister under subsection 85(1) with the actual carbon intensity determined in accordance with section 76, 78 or 79, in the case where the actual carbon intensity — as specified in the carbon-intensity-pathway report referred to in subsection 123(1) — is lower than the approved carbon intensity and the difference between the two intensities is at least

(a) 1 gCO₂e/MJ, if the absolute value of the approved carbon intensity is less than 20 gCO₂e/MJ;
(b) 5%, if the absolute value of the approved carbon intensity is between 20 and 100 gCO₂e/MJ; and
(c) 5 gCO₂e/MJ, if the absolute value of the approved carbon intensity is greater than 100 gCO₂e/MJ.

New application — carbon-intensity contributor

(2) A carbon-intensity contributor may apply to replace a carbon intensity that has been approved by the Minister under subsection 85(1) with the actual carbon intensity determined in accordance with section 76 or 79 in the case where the actual carbon intensity — as specified in the carbon-intensity-pathway report referred to in subsection 123(1) — is lower than the approved carbon intensity and the difference between the two intensities is at least

(a) 1 gCO₂e/MJ, if the absolute value of the approved carbon intensity is less than 20 gCO₂e/MJ;
(b) 5%, if the absolute value of the approved carbon intensity is between 20 and 100 gCO₂e/MJ; and
(c) 5 gCO₂e/MJ, if the absolute value of the approved carbon intensity is greater than 100 gCO₂e/MJ.

Adjustment of credits

88 (1) A registered creator may — in the first annual credit-creation report that they submit under section 120 or first credit-adjustment report that they submit under section 122 following the approval under subsection 85(1) of the carbon intensity of a fuel or energy source determined in accordance with section 76, 78 or 79 — request that compliance credits be created for the three compliance periods preceding the approval of the carbon intensity if

(a) the carbon intensity indicated in that credit-creation report or that credit-adjustment report was determined in accordance with section 75 or was temporarily approved under subsection 91(4);
(b) the fuel for which the carbon intensity was approved under subsection 85(1) is produced from the same type of feedstock and in the same production process as the fuel or electricity used during the preceding compliance periods for which a credit adjustment is requested; and
(c) the carbon intensity that was approved under subsection 85(1) was determined in accordance with section 76, 78 or 79 after July 1, 2024.

Number of adjusted compliance credits

(2) The number of compliance credits that may be created by a registered creator under subsection (1) is equal to the difference between

(a) the maximum number of compliance credits that would be created for the three compliance periods preceding the approval of the carbon intensity using the information contained in the report that they submit under section 120 or 122 in respect of those compliance periods and using the carbon intensity that was determined in accordance with section 76, 78 or 79, as the case may be, and
(b) the total number of compliance credits that were created by the registered creator for the three compliance periods preceding the approval of the carbon intensity using the carbon intensity that was determined in accordance with section 75 or that was temporarily approved under subsection 91(4), as the case may be.

Adjustment — actual carbon intensity

89 A registered creator may — in the credit-adjustment report that they submit under subsection 122(1) — request that any compliance credits that were created for a compliance period using the carbon intensity that was determined in accordance with section 76 and approved under subsection 85(1) be adjusted based on the actual carbon intensity of the fuel as specified in the carbon-intensity-pathway report that they submit under subsection 123(1) for that compliance period.

Adjustment after June 30, 2024

90 (1) If an approved carbon intensity determined in accordance with section 76, 77, 78 or 79 ceases to be valid on December 31, 2025 through the operation of subsection 86(9) and the registered creator, carbon-intensity contributor or foreign supplier made, before September 30, 2025, a new application to the Minister under subsection 80(1) for approval of the carbon intensity, the registered creator may — in the first annual credit-creation report that they submit under section 120 or first credit-adjustment report that they submit under section 122 following the approval under subsection 85(1) of the carbon intensity — request that compliance credits be created for the period beginning on the day on which they became eligible to create compliance credits under subsection 25(2) or 25(3) or paragraph 31(2)(b) or 32(2)(d), as the case may be, and ending on the day on which the new application is approved by the Minister.

Number of adjusted compliance credits

(2) The number of compliance credits that may be created under subsection (1) is equal to the difference between

(a) the maximum number of compliance credits that would be created by the registered creator for the period referred to in subsection (1) using the information contained in the report that they submit under section 120 or 121 in respect of the compliance periods that fall within that period and using the carbon intensity that was determined in accordance with any of sections 76 to 79, as the case may be, and
(b) the total number of compliance credits that were created by the registered creator for the period referred to in subsection (1) using the carbon intensity that they used to create compliance credits before June 30, 2024.

Application for temporary approval

91 (1) A registered creator or foreign supplier who has data on the operation of a facility for a period of 3 or more consecutive months, but no more than 24 consecutive months, with respect to the activities referred to in the definition carbon intensity in subsection 1(1) may apply for temporary approval of a carbon intensity.

Determination of carbon intensity

(2) The carbon intensity is to be determined in accordance with section 76, 78 or 79, as the case may be, using the data for the period referred to in subsection (1) instead of the data for 24 consecutive months that is required by those sections.

Application

(3) The application must be made in accordance with sections 80 to 84.

Temporary approval

(4) The Minister must grant temporary approval of the carbon intensity if the Minister is satisfied that the determination of the carbon intensity is based on the factors set out in subsection 85(1).

Unique alphanumeric identifier

(5) The Minister must assign a unique alphanumeric identifier to the temporarily approved carbon intensity.

Equivalent to approved carbon intensity

(6) The temporarily approved carbon intensity is to be treated as if it were approved under subsection 85(1) until

(a) the day that is 24 months after the day on which the temporary approval is granted, in the case where the registered creator or foreign supplier who applied for temporary approval has not applied for approval of that carbon intensity under section 80; or
(b) the day on which the Minister approves the carbon intensity under subsection 85(1), in any other case.

Period of validity

(7) The temporarily approved carbon intensity ceases to be valid on the day referred to in paragraph (6)(a) or (b), as the case may be, or on any earlier day on which there is a change to the extraction or production processes for the feedstock used to produce the fuel or to the fuel production processes and the change is not consistent with the emission factors, input data, background data sets or methodology that were used to determine the temporarily approved carbon intensity.

Registration of foreign supplier

92 (1) A foreign supplier may register as a foreign supplier with the Minister by submitting to the Minister a registration report that contains the following information:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent;
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent; and
(d) with respect to each facility at which they produce low-carbon-intensity fuel,
- (i) the name, GPS coordinates to the fifth decimal place and, if any, civic address of the facility, and
- (ii) the type of low-carbon-intensity fuel produced at the facility.

Pre-condition for application

(2) A foreign supplier may make an application referred to in subsection 80(1), 81(1) or 91(1) only if they are registered as a foreign supplier with the Minister.

Registration — carbon-intensity contributor

93 (1) A carbon-intensity contributor may register as a carbon-intensity contributor with the Minister by submitting to the Minister a registration report that contains the following information:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent;
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent; and
(d) with respect to each facility at which renewable natural gas, renewable propane, electricity, biogas or hydrogen is produced,
- (i) the name, GPS coordinates to the fifth decimal place and, if any, civic address of the facility, and
- (ii) the type of fuel, energy source or material input produced at the facility.

Pre-condition for application

(2) A carbon-intensity contributor may make an application referred to in subsection 80(1), 81(1) or 91(1) only if they are registered as a carbon-intensity contributor with the Minister.

Low-Carbon-Intensity Fuels

Liquid class

94 (1) A person who, during a compliance period, produces in Canada or imports into Canada a quantity of liquid low-carbon-intensity fuel that displaces, or was sold to displace, the use of a quantity of fuel in the liquid class may create provisional compliance credits in respect of the liquid class for the compliance period.

Number of compliance credits

(2) The number of compliance credits that the person may create for a compliance period in respect of the liquid low-carbon-intensity fuel is determined by the formula

CI_diff × (Q × D) × 10^-6: where
CI_diff: is the difference between the reference carbon intensity for the liquid class, as set out in item 1, column 2, of Schedule 1, and the carbon intensity of the low-carbon-intensity fuel that is the default carbon intensity referred to in paragraph 75(1)(a), the carbon intensity approved under subsection 85(1) or the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be;
Q: is, subject to subsection 45(1), the volume of the low-carbon-intensity fuel that the person produced in Canada using an eligible feedstock or imported into Canada during the compliance period that is used or sold for use in Canada as neat fuel or as part of a blend, expressed in cubic metres; and
D: is, at the election of the person, the energy density of the low-carbon-intensity fuel as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations.

Gaseous class

95 (1) A person who, during a compliance period, produces in Canada or imports into Canada a quantity of low-carbon-intensity fuel that is biogas, renewable natural gas, renewable propane or hydrogen and that displaces, or was sold to displace, the use of a volume of fuel in the gaseous class may create provisional compliance credits in respect of the gaseous class for the compliance period.

Excluded gases

(2) A person must not create provisional compliance credits under subsection (1) for a compliance period by producing or importing

(a) biogas that is converted into renewable natural gas;
(b) biogas, renewable natural gas, renewable propane or hydrogen for which provisional compliance credits were created by the carrying out of an emission-reduction project referred to in section 30;
(c) biogas for which provisional compliance credits were created under section 96; or
(d) renewable propane, renewable natural gas or hydrogen for which provisional compliance credits were created under section 100 or 104.

Exception — biogas used in equipment

(3) A person must not create provisional compliance credits under subsection (1) for a compliance period in respect of the use of biogas in equipment that produces electricity unless the amount determined by the following formula is greater than 0.7:

(E_total + H) ÷ (Q × D): where
E_total: is the total quantity of electricity produced by the equipment, expressed in megajoules;
H: is the heat energy produced by the equipment and used or sold, expressed in megajoules;
Q: is the quantity of the biogas used in the equipment, expressed in cubic metres; and
D: is, at the election of the person, the energy density of the biogas as set out in item 1, column 2, of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162.

Number of compliance credits

(4) The number of compliance credits that the person may create for a compliance period in respect of a particular fuel is determined by the formula

CI_diff × (Q × D) × 10^-6

where

CI_diff

(a) in the case of biogas, renewable natural gas or hydrogen, the difference between the reference carbon intensity of biogas, renewable natural gas and hydrogen, as set out in item 2, column 2, of Schedule 1, and the carbon intensity that is the default carbon intensity referred to in paragraph 75(1)(a), the carbon intensity approved under subsection 85(1) or the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be, and
(b) in the case of renewable propane, the difference between the reference carbon intensity of renewable propane, as set out in item 3, column 2, of Schedule 1, and the carbon intensity that is the default carbon intensity referred to in paragraph 75(1)(a), the carbon intensity approved under subsection 85(1) or the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be;

Q

is, subject to subsection 45(1), the quantity of the biogas — other than biogas referred to in paragraph (2)(a) or (2)(c) — or renewable natural gas, renewable propane or hydrogen — other than renewable natural gas, renewable propane or hydrogen referred to in paragraph (2)(d) — that was produced using an eligible feedstock in Canada or imported into Canada by the person during the compliance period and that is used or sold for use in Canada as neat fuel or as part of a blend, expressed in cubic metres in the case of biogas, renewable natural gas or renewable propane and in kilograms in the case of hydrogen; and

D

is, at the election of the person, the energy density of the biogas, renewable natural gas, renewable propane or hydrogen as set out in column 2 of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or, in the case of biogas, as measured in accordance with section 162.

Biogas used to produce electricity

96 (1) A person who, during a compliance period, produces in Canada a quantity of biogas that is used in equipment to produce electricity and that displaces the use in Canada of a volume of fuel in the gaseous class in accordance with paragraph 20(b) or (c) may create provisional compliance credits in respect of the gaseous class for the compliance period.

Electricity produced from biogas

(2) The carbon intensity of the electricity that the person produces by using biogas in equipment is determined by the formula

CI_biogas × (Q × D) ÷ E_total: where
CI_biogas: is the carbon intensity of the biogas that is used to produce electricity and that is the default carbon intensity referred to in paragraph 75(1)(a), the carbon intensity approved under subsection 85(1) or the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be;
Q: is, subject to subsection 45(1), the quantity of the biogas that is produced using an eligible feedstock and used in the equipment and determined in accordance with the Specifications for Fuel LCA Model CI Calculations, expressed in cubic metres;
D: is, at the election of the person, the energy density of the biogas as set out in item 1, column 2, of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162; and
E_total: is the total quantity of electricity produced by the equipment from the biogas, expressed in megajoules.

Number of compliance credits

(3) The number of compliance credits that a person may create under subsection (1) for a compliance period is determined by the formula

CI_diff × E × 10^-6: where
CI_diff: is the difference between the carbon intensity of electricity for the province in which the equipment used to produce the electricity is located, as determined in accordance with subsection (4), and the carbon intensity of the electricity produced from biogas, as determined in accordance with subsection (2); and
E: is the quantity of electricity that is produced, expressed in megajoules.

Carbon intensity — province

(4) The carbon intensity of electricity for the province in which the equipment that uses biogas to produce electricity is located is the lessor of the following amounts:

(a) the amount set out for that province in section 9 of Schedule 6;
(b) the amount set out for that province in the Specifications for Fuel LCA Model CI Calculations; and
(c) 96 g/MJ.

Multiple feedstocks

97 (1) A low-carbon-intensity fuel that is produced using more than one type of feedstock is considered to be multiple fuels for the purposes of paragraph 30(d) and sections 94 to 96, 100 and 104 and the quantity of each type of fuel is equal to the proportion of the low-carbon-intensity fuel that is produced using each type of feedstock.

Determination of proportion

(2) The registered creator must determine the proportion of a low-carbon-intensity fuel that is produced using each type of feedstock in accordance with the Specifications for Fuel LCA Model CI Calculations.

Co-processed low-carbon-intensity fuel

(3) The registered creator must determine the proportion of a co-processed low-carbon-intensity fuel that is produced using each type of feedstock in accordance with the applicable specific emission-reduction quantification method established under subsection 32(1).

Fuel or Other Energy Source for Vehicles

Gas for vehicles

98 (1) The owner or operator of a fuelling station who, during a compliance period, displaces the use of a fuel in the liquid class by supplying propane, compressed natural gas or liquefied natural gas for use in Canada as a fuel for a vehicle may create provisional compliance credits in respect of the liquid class for the compliance period.

Number of compliance credits

(2) The number of compliance credits that an owner or operator may create under subsection (1) for a compliance period is determined by the formula

CI_diff × (Q × D) × 10^-6

where

CI_diff

is the difference between

(a) the reference carbon intensity for the liquid class, as set out in item 1, column 2, of Schedule 1, and
(b) the carbon intensity of the propane, compressed natural gas or liquefied natural gas that is determined in accordance with subsection 75(6), that is approved under subsection 85(1) or that is the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be;

Q

is the difference between

(a) the total quantity of the fuel that contains propane, compressed natural gas or liquefied natural gas that is supplied for use as a fuel for a vehicle, as measured by a meter,
- (i) expressed in cubic metres of fuel in the liquid state, in the case of fuel that contains propane,
- (ii) expressed in cubic metres, in the case of fuel that contains compressed natural gas, and
- (iii) expressed in kilograms, in the case fuel that contains liquefied natural gas; and
(b) the quantity of the following, as determined from the supporting documents referred to in subsection 99(2):
- (i) renewable propane or co-processed low-carbon-intensity propane supplied for use as a fuel for a vehicle, expressed in cubic metres of fuel in the liquid state, if the fuel that is supplied contains propane, renewable propane or co-processed low-carbon-intensity propane, and
- (ii) renewable natural gas supplied for use as a fuel for a vehicle, expressed in cubic metres, if the fuel that is supplied contains compressed natural gas, or
- (iii) renewable natural gas supplied for use as a fuel for a vehicle, expressed in kilograms, if the fuel that is supplied contains liquefied natural gas; and

D

is, at the election of the owner or operator, the energy density of the propane, compressed natural gas or liquefied natural gas, as the case may be, as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations.

Renewable gaseous fuel

99 (1) The owner or operator of a fuelling station who, during a compliance period, displaces the use of a fuel in the liquid class by supplying low-carbon-intensity fuel that is renewable propane, co-processed low-carbon intensity propane, compressed renewable natural gas or liquefied renewable natural gas for use in Canada as a fuel for a vehicle must not create provisional compliance credits in respect of the liquid class for the compliance period unless they possess the supporting documents that are referred to in subsection (2).

Supporting documents

(2) The supporting documents must

(a) establish that the fuel was physically supplied to the fuelling station or was supplied to the fuelling station by means of a contractual agreement;
(b) indicate the quantity of the fuel that was produced, subject to subsection 45(1), using eligible feedstock that was supplied to the fuelling station by the producer of the fuel during the compliance period and indicate the name of the person from whom the fuel was purchased;
(c) if the carbon intensity of the fuel has been approved by the Minister under subsection 85(1), indicate that carbon intensity and the alphanumeric identifier assigned to that carbon intensity under subsection 85(2);
(d) if the carbon intensity of the fuel has not been approved by the Minister under subsection 85(1), indicate the name of the producer of the fuel, their civic address, postal address, telephone number and, if any, their email address and the name, GPS coordinates to the fifth decimal place and, if any, the civic address of the facility at which the fuel was produced; and
(e) if the fuel was supplied by means of a contractual agreement, establish that there is a physical connection between the fuelling station and the producer of the fuel and that the quantity of the fuel supplied to vehicles at the fuelling station during the compliance period does not exceed the quantity of the fuel produced by the producer of the fuel and injected in a pipeline during the compliance period.

Number of compliance credits

(3) The number of compliance credits that the owner or operator of a fuelling station that supplies a low-carbon-intensity fuel that is compressed renewable natural gas or liquefied renewable natural gas may create for a compliance period is determined by the formula

(CI_diff1 + CI_diff2) × (Q × D) × 10^-6

where

CI_diff1

is the difference between

(a) the reference carbon intensity for the liquid class, as set out in item 1, column 2, of Schedule 1, and
(b) the carbon intensity of the compressed renewable natural gas or liquefied renewable natural gas that is determined in accordance with subsection 75(6), that is approved under subsection 85(1) or that is the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be;

CI_diff2

is the difference between

(a) the carbon intensity of natural gas that is determined in accordance with subsection 75(6), and
(b) the reference carbon intensity of renewable natural gas, as set out in item 2, column 2, of Schedule 1;

Q

is, subject to subsection 45(1), the quantity of the renewable natural gas supplied to the vehicles, expressed in cubic metres in the case of compressed renewable natural gas or in kilograms in the case of liquefied renewable natural gas, as determined from the supporting documents referred to in subsection (2); and

D

is, at the election of the owner or operator, the energy density of renewable natural gas as set out in item 2, column 2, of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations.

Renewable propane

(4) The number of compliance credits that the owner or operator of a fuelling station that supplies a low-carbon-intensity fuel that is renewable propane or co-processed low-carbon intensity propane may create for a compliance period is determined by the formula

(CI_diff1 + CI_diff2) × (Q × D) × 10^-6

where

CI_diff1

is the difference between

(a) the reference carbon intensity for the liquid class, as set out in item 1, column 2, of Schedule 1, and
(b) the carbon intensity of the propane that is determined in accordance with subsection 75(6), that is approved under subsection 85(1) or that is the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be;

CI_diff2

is the difference between

(a) the carbon intensity of propane, as determined in accordance with subsection 75(6), and
(b) the reference carbon intensity of renewable propane, as set out in item 3, column 2, of Schedule 1;

Q

is, subject to subsection 45(1), the quantity of the renewable propane or co-processed low-carbon intensity propane supplied to the vehicles, expressed in cubic metres of fuel in the liquid state, as determined from the supporting documents referred to in subsection (2); and

D

is, at the election of the owner or operator, the energy density of renewable propane as set out in item 7, column 2, of Schedule 2 or in the Specifications for Fuel LCA Model CI Calculations.

Creator — producer or importer

100 (1) A person who, during a compliance period, displaces the use of a fuel in the liquid class by producing in Canada or importing into Canada, a quantity of low-carbon-intensity fuel that is renewable propane or renewable natural gas for use in Canada as a fuel for a vehicle must not create provisional compliance credits in respect of the liquid class for the compliance period unless they possess supporting documents that

(a) establish that the fuel was physically supplied to a fuelling station or supplied to the fuelling station by means of a contractual agreement;
(b) indicate the name of the owner or operator of the fuelling station;
(c) indicate the quantity of the fuel that was supplied to the fuelling station during the compliance period;
(d) establish that the quantity of the fuel that was supplied by the producer to the fuelling station and used to create compliance credits during the compliance period does not exceed the quantity of the fuel that was supplied to vehicles at the fuelling station during the compliance period; and
(e) if the fuel was supplied to the fuelling station by means of a contractual agreement, establish that there is a physical connection between the fuelling station and the producer of the fuel.

Number of compliance credits

(2) The number of compliance credits that the person referred to in subsection (1) may create for a compliance period in respect of a particular fuel is determined by the formula

CI_diff × (Q × D) × 10^-6

where

CI_diff

(a) in the case of renewable natural gas, the difference between the reference carbon intensity of renewable natural gas, as set out in item 2, column 2, of Schedule 1, and the carbon intensity of the renewable natural gas that is the default carbon intensity referred to in paragraph 75(1)(a), the carbon intensity approved under subsection 85(1) or the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be, and
(b) in the case of renewable propane, the difference between the reference carbon intensity of renewable propane, as set out in item 3, column 2, of Schedule 1, and the carbon intensity of the renewable propane that is the default carbon intensity referred to in paragraph 75(1)(a), the carbon intensity approved under subsection 85(1) or the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be;

Q

is, subject to subsection 45(1), the quantity of the fuel supplied to the fuelling station, expressed in cubic metres, as determined from the supporting documents referred to in subsection (1); and

D

is, at the election of the person, the energy density of the fuel as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations.

Electricity — charging-site host

101 (1) A charging-site host may, for a compliance period, create provisional compliance credits in respect of the liquid class by displacing, during the compliance period, the use in Canada of a quantity of fuel in the liquid class with the use in Canada of electricity as an energy source for an electric vehicle of a class that is listed in the Specifications for Fuel LCA Model CI Calculations, if the electricity is supplied to that electric vehicle by a charging station other than any charging station referred to in subsection 102(1).

Number of compliance credits

(2) The number of compliance credits that the charging-site host may create under subsection (1) for a compliance period by supplying electricity of a particular carbon intensity to electric vehicles is determined by the formula

CI_diff × (Q × D) × 10^-6: where
CI_diff: is the difference between the reference carbon intensity for the liquid class for the compliance period, as set out in item 1, column 2, of Schedule 1 and adjusted by the energy efficiency ratio of the electric vehicles, and the carbon intensity of the electricity used by those electric vehicles, as determined by the formula

(R_ee × CI_ref) − CI_e

where

R_ee

(a) if the electricity is supplied by a charging station that is not accessible to electric marine vessels,
- (i) in the case of light-duty electric vehicles, at the election of the registered creator, the energy efficiency ratio on the January 1 of the compliance period for the light-duty class of electric vehicles, as set out in the Specifications for Fuel LCA Model CI Calculations, or an energy efficiency ratio of 2.5, or
- (ii) in the case of any other class of electric vehicles, at the election of the registered creator, the energy efficiency ratio on the January 1 of the compliance period for the class of the electric vehicles, as set out in the Specifications for Fuel LCA Model CI Calculations, or an energy efficiency ratio of 2.5,
(b) if the electricity is supplied by a charging station that is accessible to electric marine vessels, at the election of the registered creator, the energy efficiency ratio on the January 1 of the compliance period for the class of the electric vehicles, as set out in the Specifications for Fuel LCA Model CI Calculations, or an energy efficiency ratio of 2.5, or
(c) if the electricity is supplied by a charging station that is accessible to more than one class of electric vehicles and it is not possible to differentiate between the quantity of electricity supplied to each class of electric vehicles, the energy efficiency ratio that is the lesser of the energy efficiency ratios determined under paragraph (a) and (b),

CI_ref

is the reference carbon intensity for the liquid class for the compliance period, as set out in item 1, column 2, of Schedule 1, and

CI_e

is the carbon intensity of the electricity supplied to the electric vehicles that is determined in accordance with subsection 75(7), that is approved under subsection 85(1) or that is the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be;

Q

is the quantity of electricity supplied to the electric vehicles, expressed in kilowatt-hours, as measured by charging stations other than those referred to in subsection 102(1), subject to any measurement accuracy or load test tolerances for charging stations that are indicated in the document entitled Specifications, Tolerances, and Other Technical Requirements for Weighing and Measuring Devices, published by the United States National Institute of Standards and Technology; and

D

is 3.6 megajoules per kilowatt-hour.

Electricity – charging-network operator

102 (1) A charging-network operator may, for a compliance period, create provisional compliance credits in respect of the liquid class by displacing, during the compliance period, the use in Canada of a quantity of fuel in the liquid class with the use in Canada of electricity as an energy source for an electric vehicle of a class that is listed in the Specifications for Fuel LCA Model CI Calculations, if

(a) the compliance period begins on or before January 1, 2035 and the electricity is supplied to that electric vehicle by a charging station that is owned and intended primarily for use by the occupants of a private dwelling-place and that is installed on or before December 31, 2030; or
(b) the electricity is supplied to that electric vehicle by a charging station that is intended primarily for use by the public and whose location is indicated on the website or mobile application of the charging-network operator.

Number of compliance credits

(2) The number of compliance credits that the charging-network operator may create under subsection (1) for a compliance period by supplying electricity of a particular carbon intensity is determined by the formula

CI_diff × (Q × D) × 10^-6: where
CI_diff: is the difference between the reference carbon intensity for the liquid class for the compliance period, as set out in item 1, column 2, of Schedule 1 and adjusted by the energy efficiency ratio of the electric vehicles, and the carbon intensity of the electricity used by those vehicles, as determined by the formula

(R_ee × CI_ref) − CI_e: where
R_ee: is, at the election of the registered creator, the energy efficiency ratio for the light-duty class of the electric vehicles, as set out in the Specifications for Fuel LCA Model CI Calculations on the January 1 of the compliance period, or an energy efficiency ratio of 2.5,
CI_ref: is the reference carbon intensity for the liquid class for the compliance period, as set out in item 1, column 2, of Schedule 1, and
CI_e: is the carbon intensity of the electricity supplied to the electric vehicles that is determined in accordance with subsection 75(7), that is approved under subsection 85(1) or that is the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1), as the case may be;
Q: is the quantity of electricity supplied to the electric vehicles, expressed in kilowatt-hours, as measured by the charging stations referred to in subsection (1), subject to any measurement accuracy or load test tolerances for charging stations that are indicated in the document entitled Specifications, Tolerances, and Other Technical Requirements for Weighing and Measuring Devices, published by the United States National Institute of Standards and Technology; and
D: is 3.6 megajoules per kilowatt-hour.

Use of revenue — electric vehicles

103 (1) A charging-network operator referred to in subsection 102(1), or a person with whom they have entered into an agreement under section 21, must not create compliance credits under section 102 during a compliance period unless all of the revenue that they receive from the transfer of compliance credits created under that section during all previous compliance periods is used within the time limit set out in subsection (3) for the purpose of carrying out, in Canada, either of the following activities:

(a) expanding electric vehicle charging infrastructure, including charging stations and electricity distribution infrastructure that supports electric vehicle charging, whether intended primarily for use by the occupants of a private dwelling-place or the public; or
(b) reducing the cost of electric vehicle ownership through financial incentives to purchase or operate an electric vehicle.

Allocation to activities

(2) The charging-network operator or person may, at their discretion, allocate the use of those revenues to either or both of those activities.

Period for use

(3) The revenues received by the charging-network operator or person, from the transfer of a compliance credit, must be used no later than the second anniversary of the end of the compliance period during which the compliance credit is transferred.

Cancellation of credits

(4) The Minister must cancel an equivalent number of compliance credits to the number of compliance credits that were transferred if the revenue from that transfer is not used in accordance with subsection (1).

Insufficient number of credits

(5) If the number of compliance credits that must be cancelled under subsection (4) is greater than the number of compliance credits in the account of the charging-network operator or person, the Minister must send a notice to them indicating the number of compliance credits that are missing.

Obligation to replace credits

(6) The charging-network operator or person must, within 90 days after the day on which the notice referred to in subsection (5) is sent, ensure that the number of compliance credits in the same account is equivalent to the number of compliance credits that are missing.

Notice to Minister

(7) The charging-network operator or person must, when their account contains the equivalent number of compliance credits required under subsection (6) and within the time limit set out in that subsection, send a notice to the Minister indicating that their account contains that equivalent number of compliance credits.

Cancellation of compliance credits

(8) On receipt of the notice referred to in subsection (7), the Minister must cancel the equivalent number of compliance credits that are indicated.

Hydrogen

104 (1) The owner or operator of a hydrogen fuelling station may, for a compliance period, create provisional compliance credits in respect of the liquid class by displacing, during the compliance period, the use in Canada of a quantity of fuel in the liquid class with the use in Canada of hydrogen, either as

(a) an energy source for a hydrogen fuel cell vehicle of a class that is listed in the Specifications for Fuel LCA Model CI Calculations; or
(b) a fuel for a vehicle, other than a hydrogen fuel cell vehicle, of a class that is listed in the Specifications for Fuel LCA Model CI Calculations.

Number of compliance credits

(2) The number of compliance credits that the owner or operator may create under subsection (1) for a compliance period by supplying hydrogen of a particular carbon intensity to vehicles is determined by the formula

CI_diff × (Q × D) × 10^-6: where
CI_diff: is the difference between the reference carbon intensity for the liquid class, as set out in item 1, column 2, of Schedule 1 and adjusted by the energy efficiency ratio of the vehicles, and the carbon intensity of the hydrogen used by those vehicles, as determined by the formula

(R_ee × CI_ref) − CI_h

where

R_ee

(a) in the case of the use referred to in paragraph (1)(a), at the election of the owner or operator, 1.5 or the energy efficiency ratio for the class of the hydrogen fuel cell vehicles, as set out in the Specifications for Fuel LCA Model CI Calculations, and
(b) in the case of the use referred to in paragraph (1)(b), at the election of the owner or operator, 0.9 or the energy efficiency ratio for the class of vehicles other than hydrogen fuel cell vehicles, as set out in the Specifications for Fuel LCA Model CI Calculations,

CI_ref

is the reference carbon intensity for the liquid class, as set out in item 1, column 2, of Schedule 1, and

CI_h

is the carbon intensity of the hydrogen supplied to the vehicles that is the default carbon intensity referred to in paragraph 75(1)(a), the carbon intensity determined in accordance with paragraph 75(1)(b) or subsection 75(6), the carbon intensity that is approved under subsection 85(1) or the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1);

Q

is, subject to subsection 45(1), the quantity of the hydrogen of the particular carbon intensity that is produced using an eligible feedstock and supplied to the vehicles, as measured by a meter and expressed in kilograms; and

D

is, at the election of the owner or operator, the energy density of the hydrogen, as set out in item 4, column 2, of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations.

Compliance-Credit Transfer System

General

Participating registered creator

105 (1) A registered creator who is not a registered primary supplier becomes a participant in the compliance-credit transfer system as of the first day on which they create a provisional compliance credit.

Participating primary supplier

(2) A primary supplier becomes a participant in the compliance-credit transfer system as of the day on which they register as a primary supplier under subsection 10(1).

Eligibility to transfer credits

106 (1) Only a participant may transfer a compliance credit and the transfer must be to another participant.

Transfer request

(2) A participant who wishes to transfer any compliance credits to another participant must submit a transfer request to the Minister that is signed by their authorized agent and contains the following information:

(a) the name, civic address and postal address of the transferor;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of the transferor’s authorized agent;
(c) the name, civic address and postal address of the transferee;
(d) the name, title, civic address, postal address, telephone number and, if any, email address of the transferee’s authorized agent; and
(e) with respect to any compliance credits that are to be transferred, an indication of
- (i) their number,
- (ii) their specific type,
- (iii) the year in which they were created,
- (iv) the price, if any, to be paid to the transferor by the transferee for each compliance credit, and
- (v) the volume and carbon intensity of the fuel used to create the compliance credits.

Types of compliance credits

(3) The specific types of compliance credits are the following:

(a) compliance credits in respect of the liquid class that are created under paragraph 19(1)(a)
- (i) by carrying out a CO₂e-emission-reduction project described in paragraph 30(d) that results in the production of a co-processed low-carbon-intensity fuel that is a gasoline replacement referred to in subsection 6(1),
- (ii) by carrying out a CO₂e-emission-reduction project described in paragraph 30(d) that results in the production of a co-processed low-carbon-intensity fuel that is a diesel replacement referred to in subsection 7(1),
- (iii) by carrying out a CO₂e-emission-reduction project using a generic emission-reduction quantification method established under subsection 31(1), or
- (iv) by carrying out a CO₂e-emission-reduction project described in section 30, other than one described in subparagraphs (i) to (iii);
(b) compliance credits in respect of the liquid class that are created under paragraph 19(1)(b)
- (i) by importing a gasoline replacement referred to in subsection 6(1),
- (ii) by importing a diesel replacement referred to in subsection 7(1), or
- (iii) by importing any other liquid low-carbon-intensity fuel;
(c) compliance credits in respect of the liquid class that are created under paragraph 19(1)(c)
- (i) by producing a gasoline replacement referred to in subsection 6(1),
- (ii) by producing a diesel replacement referred to in subsection 7(1), or
- (iii) by producing any other liquid low-carbon-intensity fuel;
(d) compliance credits in respect of the liquid class that are created under paragraph 19(1)(d);
(e) compliance credits in respect of the gaseous class that are created under paragraph 20(a) by carrying out a CO₂e-emission-reduction project described in paragraph 30(d);
(f) compliance credits in respect of the gaseous class that are created under paragraph 20(b) by importing a gaseous low-carbon-intensity fuel; and
(g) compliance credits in respect of the gaseous class that are created under paragraph 20(c) by producing a gaseous low-carbon-intensity fuel.

Confirmation by transferee

(4) The authorized agent of the transferee must sign the transfer request to confirm that the information is accurate and that the transferee accepts the transfer of the compliance credits.

Transfer of credits

(5) If the transfer request submitted to the Minister meets the requirements of subsections (2) to (4), the compliance credits described in the request must be withdrawn from the transferor’s account opened under paragraph 28(a) or (b), as the case may be, and deposited into the account of the transferee that was opened under the same paragraph.

Exception — registered creator

(6) However, a participant must not transfer any compliance credit to a registered creator who is not a primary supplier and who

(a) has entered into an agreement under section 21 at any time during the ongoing compliance period or the two compliance periods that ended most recently if
- (i) the registered creator is no longer a party to that agreement, and
- (ii) the registered creator’s registration report, as updated in accordance with section 26, does not indicate that they are carrying out any of the activities referred to in subsection 19(1) or section 20; or
(b) has not created compliance credits for the two compliance periods that ended most recently.

Fair market value

107 The price paid for the transfer of a compliance credit that is created under subsection 102(1) must not be less than its fair market value.

Transfer of Compliance Credits

Transfer on creation

108 (1) A registered creator who has created provisional compliance credits under paragraph 19(1)(b) or (c) or 20(b) or (c) by producing in Canada or importing into Canada a quantity of low-carbon-intensity fuel must not transfer those provisional compliance credits to a participant who is purchasing that low-carbon-intensity fuel unless the registered creator and the transferee submit a transfer request to the Minister that is signed by the authorized agent of the registered creator as well as the authorized agent of the transferee and contains the information referred to in subsection (2).

Request to transfer — form

(2) The registered creator must indicate in the transfer request their intention to have the compliance credits that have been deposited into their account under subsection 24(1) or (2) immediately transferred to the transferee and must include the following information in the transfer request:

(a) the name, civic address and postal address of the registered creator;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of the registered creator’s authorized agent;
(c) the name, civic address and postal address of the transferee;
(d) the name, title, civic address, postal address, telephone number and, if any, email address of the transferee’s authorized agent;
(e) the type of low-carbon-intensity fuel used to create the compliance credits;
(f) the carbon intensity of the low-carbon-intensity fuel used to create the compliance credits and any alphanumeric identifier assigned to it; and
(g) the compliance period to which the transfer relates.

Immediate transfer

109 After the Minister receives the transfer request, any compliance credits deposited by the Minister during the compliance period referred to in paragraph 108(2)(g) into the registered creator’s account opened under paragraph 28(a) or (b), as the case may be, must be immediately withdrawn from that account and deposited into the transferee’s account opened under the same paragraph.

Compliance-Credit Clearance Mechanism

Pledging credits to mechanism

110 (1) A participant may, in a report submitted under subsection 126(1) or 127(1), pledge to offer to transfer through the compliance-credit clearance mechanism any compliance credits that

(a) are in an account that was opened under paragraph 28(a);
(b) were created as provisional compliance credits on or before the last day of the compliance period to which the report relates; and
(c) are not suspended under section 158.

Restriction

(2) During the period beginning on the day on which a report referred to in subsection (1) is submitted and ending on the following October 31 or, if a notice is sent in accordance with subsection 111(1), ending on the day on which that notice is sent, a participant must not use a compliance credit that a participant has pledged to offer to transfer and must not transfer that compliance credit except through the compliance-credit clearance mechanism.

No clearance mechanism

111 (1) If the compliance reports submitted under subsection 127(1) for a compliance period indicate that all primary suppliers have satisfied the total reduction requirements, the Minister must, before the following August 31, send a notice to each participant who has pledged to offer to transfer compliance credits under subsection 110(1) that informs them that there will be no compliance-credit clearance mechanism for that compliance period.

No pledge to transfer credits

(2) If no participant pledges, in a report submitted under subsection 126(1) or 127(1) for a compliance period, to offer to transfer a compliance credit through the compliance-credit clearance mechanism, the Minister must, before the following August 31, send a notice to each primary supplier who has not satisfied the total reduction requirement that informs them that there will be no compliance-credit clearance mechanism for that compliance period.

Notice to participants

(3) If subsections (1) and (2) do not apply, the Minister must, before the August 31 that follows the end of the compliance period, send a notice to each participant who has pledged to offer to transfer compliance credits under subsection 110(1) and to each primary supplier who has not yet satisfied the total reduction requirement that informs them that a compliance-credit clearance mechanism will take place for that compliance period. The notice must include the following information:

(a) the total number of compliance credits for all participants in respect of which a pledge to offer to transfer has been made under subsection 110(1);
(b) the names of all participants who have pledged to offer to transfer compliance credits under subsection 110(1); and
(c) the value of the total reduction requirement that has not been satisfied by all primary suppliers.

Transfer through clearance mechanism

112 (1) A participant must not transfer any compliance credits through the compliance-credit clearance mechanism to a primary supplier unless the transfer request referred to in subsection 106(2) has been submitted to the Minister, along with a compliance report under subsection 127(1) indicating that the primary supplier has not satisfied the total reduction requirement for the compliance period to which the report relates by using all their compliance credits in accordance with subsection 13(1), (2) or (4). The transfer of compliance credits to that primary supplier must occur during the period beginning on the August 31 that follows the end of that compliance period and ending on the following October 31.

Acquisition of compliance credits by primary supplier

(2) A primary supplier who has submitted a report under subsection 127(1) indicating that they have not satisfied the total reduction requirement for the compliance period to which the report relates by using all their compliance credits in accordance with subsection 13(1), (2) or (4) must acquire, by transfer through the compliance-credit clearance mechanism, the number of compliance credits determined in accordance with subsection (5) for that compliance period.

Maximum price

(3) A participant who has pledged to offer to transfer a compliance credit must accept an offer to acquire the compliance credit by transfer through the compliance-credit clearance mechanism if the compliance credit is in their account and the price offered for the transfer is equal to or less than the amount determined by the formula

$300 × (CPI_A ÷ CPI_B): where
CPI_A: is the average Consumer Price Index for the calendar year to which the compliance period relates, as published by Statistics Canada under the Statistics Act; and
CPI_B: is the average Consumer Price Index for the 12 months of the year 2022, as published by Statistics Canada under the Statistics Act.

Prohibition

(4) A participant who has pledged to offer to transfer a compliance credit must not accept an offer to acquire the compliance credit by transfer through the compliance-credit clearance mechanism if the amount offered for the transfer is higher than the amount determined in accordance with subsection (3).

Credits per primary supplier

(5) A primary supplier must not acquire a greater number of compliance credits by transfer through the compliance-credit clearance mechanism than the lesser of

(a) the total number of compliance credits that they require in order to satisfy the total reduction requirement as indicated in the compliance report that they submitted under subsection 127(1), and
(b) the number determined by the formula

C × (R_p ÷ R_t): where
C: is the total number of compliance credits from all participants that are subject to any pledges made under subsection 110(1),
R_p: is the total number of compliance credits that the primary supplier requires in order to satisfy the total reduction requirement, and
R_t: is the total number of compliance credits that all primary suppliers require in order to satisfy the total reduction requirement.

Registered Emission-Reduction Funding Program

Registration

113 Subject to section 115, the Minister may register a funding program whose purpose is the reduction of CO₂e emissions

(a) on application by a person under section 114 to register the emission-reduction funding program, if the conditions set out in that section are met; or
(b) on the Minister’s own initiative, if the emission-reduction funding program is established under an Act of Parliament and operates in Canada.

Application for registration

114 (1) A person who administers an emission-reduction funding program may apply to the Minister to register the program if

(a) the person is an agent of Her Majesty in right of Canada or an agent or mandatary of Her Majesty in right of a province or the person is a non-profit corporation that is established by or under a law of Canada or of a province; and
(b) the program operates in Canada.

Contents of application

(2) The application must contain the information referred to in Schedule 9 and be accompanied by an attestation, signed by the person’s authorized agent, that

(a) the emission-reduction funding program will distribute contributions made to the program to the projects referred to in subsection 115(1); and
(b) the person will make publicly available, no later than the December 31 following the end of the compliance period in respect of which those contributions are made, a report containing the information referred to in section 2 of Schedule 10.

Registration — conditions

115 (1) The Minister must not register an emission-reduction funding program under section 113 unless the Minister is satisfied that all contributions made to the program will be used to fund projects that support the deployment or commercialization of technologies or processes that will reduce CO₂e emissions by

(a) December 31, 2030, in the case of a contribution made on or before December 31, 2025; and
(b) the fifth anniversary of the day on which the contribution is made, in any other case.

Factors

(2) In deciding whether to register the emission-reduction funding program, the Minister must take into consideration

(a) the program’s policies, criteria or procedures for the distribution of contributions, including its policy for avoiding conflicts of interest regarding the distribution of contributions;
(b) the quality of the program’s financial and management control systems, information systems and management practices; and
(c) whether the person who administers the program has failed to make publicly available, no later than the December 31 that follows the end of the compliance period during which contributions are made to the program, the information referred to in section 2 of Schedule 10.

Cancelling registration

116 The Minister must cancel the registration of an emission-reduction funding program if any of the following occurs:

(a) the Minister, taking into consideration the factors set out in subsection 115(2), is no longer satisfied that contributions made to the program are being used in accordance with subsection 115(1);
(b) the person who administers the program fails to ensure that a financial audit of the program is conducted each year and, in the case of a program registered under paragraph 113(a), fails to ensure that such an audit is conducted by an independent body;
(c) the person who administers the program fails to submit to the Minister, no later than the December 31 following the end of the compliance period during which contributions are made to the program for the purposes of subsection 13(3) or 14(3), a report with respect to the operation of the program during each compliance period that contains the information referred to in Schedule 10;
(d) the person who administers the program fails to make publicly available, no later than the December 31 following the end of the compliance period in respect of which the contributions are made to the program, the information referred to in section 2 of Schedule 10;
(e) in the case of a program registered under paragraph 113(a), the program no longer meets the conditions set out in subsection 114(1);
(f) in the case of a program registered under paragraph 113(b), the provision of the Act of Parliament referred to in that paragraph that establishes the program is repealed or the program no longer operates in Canada.

List of programs

117 The Minister must make a list of all registered emission-reduction funding programs publicly available.

Contribution to funding program

118 (1) A registered primary supplier may create compliance credits for a compliance period by contributing to a registered emission-reduction funding program during

(a) the period beginning on the January 1 that follows the end of the compliance period and ending on the following July 31; or
(b) the period beginning on the October 31 that follows the end of the compliance period and ending on the following November 30.

Receipt

(2) A primary supplier who creates compliance credits by contributing to a emission-reduction funding program must provide to the Minister, with the report they submit under section 127 or 128, as the case may be, a receipt issued by the program that establishes that they made the contribution.

Compliance credits created

(3) The number of compliance credits that the primary supplier may create under subsection (1) for a compliance period is determined by the formula

C ÷ P: where
C: is the amount of the primary supplier’s contribution to the registered emission-reduction funding program; and
P: is $350.

Consumer Price Index

(4) On every January 1 that follows the end of a compliance period, the amount set out in subsection (3) for P is replaced by the result determined by the following formula, rounded to the nearest dollar or, if the result is halfway between two consecutive whole numbers, to the greater of those whole numbers:

$350 x (CPI_A ÷ CPI_B): where
CPI_A: is the average Consumer Price Index for the calendar year to which the compliance period relates, as published by Statistics Canada under the Statistics Act; and
CPI_B: is the average Consumer Price Index for the 12 months of the year 2022, as published by Statistics Canada under the Statistics Act.

Deposit into account

(5) The number of compliance credits created by a primary supplier under subsections (1) to (4) must be deposited into their account that was opened under paragraph 28(a).

No subsequent transfer

119 (1) A primary supplier must not transfer a compliance credit that they created under subsection 118(1).

Cancellation on December 1

(2) The Minister must cancel any compliance credit created under subsection 118(1) that has not been used on the December 1 that follows its creation.

Reporting

Annual credit-creation report

120 (1) A registered creator must submit to the Minister, no later than the April 30 of the calendar year that follows the end of a compliance period, a report respecting the creation of compliance credits during that compliance period under paragraph 19(1)(a), subparagraph 19(1)(d)(i), (ii), (iv) or (v) or paragraph 20(a).

Contents of report

(2) The credit-creation report must be signed by the authorized agent of the registered creator and contain the information referred to in Schedule 11 for the compliance period to which the report relates.

June 30, 2023

(3) Despite subsection (1), the registered creator must submit the credit-creation report for the compliance period that ends on December 31, 2022 no later than June 30, 2023.

April 30, 2024 — single report

(4) The registered creator must combine the credit-creation reports required under subsection (1) for the compliance period that ends on June 30, 2023 and the compliance period that ends on December 31, 2023 into a single report and submit that report no later than April 30, 2024.

Quarterly credit-creation reports

121 (1) A registered creator must submit to the Minister within the following time limits the following reports respecting the creation of compliance credits during a compliance period under paragraph 19(1)(b) or (c), subparagraph 19(1)(d)(iii) or paragraph 20(b) or (c):

(a) no later than the June 30 of the compliance period, a report respecting the creation of compliance credits between the January 1 and the March 31 of that compliance period;
(b) no later than the September 30 of the compliance period, a report respecting the creation of compliance credits between the April 1 and the June 30 of that compliance period;
(c) no later than the December 31 of the compliance period, a report respecting the creation of compliance credits between the July 1 and the September 30 of that compliance period; and
(d) no later than the March 31 of the calendar year that follows the end of the compliance period, a report respecting the creation of compliance credits between the October 1 and the December 31 of that compliance period.

Contents of report

(2) The credit-creation report for each three-month period referred to in subsection (1) must be signed by the authorized agent of the registered creator and must contain the information referred to in Schedule 12 for the period to which the report relates.

June 30, 2023 — single report

(3) The registered creator must combine the reports required under subsection (1) for the compliance period that ends on December 31, 2022 into a single report that contains the information referred to in Schedule 12 for each three-month period referred to in that subsection and submit that report no later than June 30, 2023.

Credit-adjustment report

122 (1) A registered creator who creates compliance credits during a compliance period under paragraph 19(1)(b) or (c), subparagraph 19(1)(d)(iii) or paragraph 20(b) or (c) that are the subject of a quarterly credit-creation report submitted under section 121 must submit to the Minister, no later than the June 30 of the year that follows the end of the compliance period, a report on any adjustment of the number of compliance credits that have been deposited into the registered creator’s accounts under subsection 24(1) or (2).

Contents of report

(2) The credit-adjustment report must be signed by the authorized agent of the registered creator and include the information that is set out in Schedule 13.

Non-application

(3) Subsection (1) does not apply in respect of any compliance period that ends before January 1, 2023.

Carbon-intensity-pathway report

123 (1) A registered creator, carbon-intensity contributor or foreign supplier who obtains approval of the carbon intensity of a fuel, energy source or material input under subsection 85(1) must submit to the Minister, for the compliance period during which the approval is obtained and for each compliance period that follows, a carbon-intensity-pathway report no later than the April 30 that follows the end of the compliance period.

Contents of report

(2) The carbon-intensity-pathway report must contain the information referred to in Schedule 14 for the compliance period and must be signed by the authorized agent of the registered creator, carbon-intensity contributor or foreign supplier.

Non-application

(3) Subsection (1) does not apply in respect of any compliance period that ends before January 1, 2024.

2024 compliance period

(4) Despite subsection (1), a registered creator, carbon-intensity contributor or foreign supplier who has received approval of a carbon intensity of a fuel, energy source or material input under subsection 85(1) after July 1, 2024 may, for the compliance period that ends on December 31, 2024, submit the carbon-intensity-pathway report on or before April 30, 2025.

Material balance report

124 (1) A registered creator or foreign supplier must submit a material balance report to the Minister no later than the April 30 that follows the end of each compliance period in respect of any gaseous or liquid low-carbon-intensity fuel that has a carbon intensity referred to in subsection 45(2) and was produced using a quantity of an eligible feedstock referred to in paragraph 46(1)(b) or (c).

Contents of report

(2) The material balance report must contain the information referred to in Schedule 15 for the compliance period and must be signed by the authorized agent of the registered creator or foreign supplier.

Non-application

(3) Subsection (1) does not apply in respect of any compliance period that ends before January 1, 2024.

Compliance-credit revenue report

125 (1) A registered creator who is a charging-network operator must submit to the Minister, for each compliance period, a report respecting revenue received from the transfer of compliance credits that specifies

(a) the amount of revenue received during the compliance period from the transfer of compliance credits created under subsection 102(1), no later than the July 31 that follows the end of the compliance period; and
(b) the use that they made, during the compliance period and the following two compliance periods, of the revenue referred to in paragraph (a), no later than the July 31 that follows the end of the third compliance period.

Contents of report

(2) The compliance-credit revenue report required under subsection (1) must contain the information referred to in Schedule 16 and must be signed by the authorized agent of the registered creator.

Non-application

(3) Subsection (1) does not apply in respect of any compliance period that ends before January 1, 2023.

Compliance-credit balance report

126 (1) A registered creator or a primary supplier must submit to the Minister a compliance-credit balance report no later than the August 15 that follows the end of a compliance period.

Contents of report

(2) The compliance-credit balance report must contain the information referred to in Schedule 17 with respect to compliance credits in the registered creator’s or primary supplier’s accounts on the day on which the report is submitted and must be signed by the authorized agent of the registered creator or primary supplier, as the case may be.

Non-application

(3) Subsection (1) does not apply in respect of any compliance period that ends before January 1, 2023.

Compliance report

127 (1) A registered primary supplier must, no later than the July 31 that follows the end of each compliance period, submit a report to the Minister with respect to their compliance for the compliance period with the volumetric requirements set out in subsections 6(1) and 7(1) and the total reduction requirement.

Contents of report

(2) The compliance report must contain the information referred to in Schedule 18 for the compliance period and be signed by the authorized agent of the primary supplier.

Non-application

(3) Subsection (1) does not apply in respect of any compliance period that ends before July 1, 2023.

Complementary compliance report

128 (1) A registered primary supplier who, by the July 31 that follows the end of a compliance period, has not satisfied the total reduction requirement must submit to the Minister a complementary compliance report no later than the December 15 that follows the end of the compliance period.

Contents of report

(2) The complementary compliance report must contain the information referred to in Schedule 19 for the compliance period and must be signed by the authorized agent of the primary supplier.

Non-application

(3) Subsection (1) does not apply in respect of any compliance period that ends before July 1, 2023.

Verification

Obligation to Verify

Condition of eligibility — reports and applications

129 A report or application that is referred to in either section 130 or 131 is ineligible if it is not verified in accordance with the requirements set out in sections 132 to 154.

Verification of applications

130 (1) A person who makes either of the following applications must have the application verified by a verification body and must submit the verification report prepared by the body with that application:

(a) an application made under subsection 80(1) in respect of a carbon intensity determined in accordance with any of sections 76 to 79; or
(b) an application made under subsection 91(1) for the temporary approval of a carbon intensity.

Non-application

(2) Subsection (1) does not apply in respect of an application made before June 30, 2024.

Verification of reports

131 (1) A person who is required to submit a report under any of section 120, subsection 121(3) and sections 122 to 125 and 127 and 128 must have it verified by a verification body and obtain a verification report prepared by the body.

Exception

(2) However, a report is not required to be verified if,

(a) in the case of a report submitted under section 120, subsection 121(3) or section 122, no compliance credits were created during the compliance period to which the report relates; or
(b) in the case of a report submitted under section 125, no revenue was created from the transfer of compliance credits during the compliance period to which the report relates or the two preceding compliance periods.

Submission of verification report

(3) The person referred to in subsection (1) must submit the verification report to the Minister together with the report to which it relates.

Declarations

132 A person who is having either of the following reports verified must submit a copy of all the declarations referred to in paragraph 57(2)(a) to the verification body:

(a) a report submitted under section 120, 121 or 122 that indicates that compliance credits were created by the carrying out of a CO₂e-emission-reduction project described in paragraph 30(d) or under any of sections 94 to 96, 99, 100 and 104, as the case may be, by the production in Canada or import into Canada of a low-carbon-intensity fuel after December 31, 2022; or
(b) a report submitted under section 124.

Contents of verification report

133 The verification report must contain the information referred to in Schedule 20.

Management system and processes

134 The books and records related to a verification that must be retained in accordance with subsection 166(2) include any that

(a) support the information contained in the application or the report being verified and allow that information to be recreated;
(b) demonstrate that the application or the report being verified meets the requirements of these Regulations;
(c) contain information that relates to the functioning of the verification body’s management system and processes and its compliance with that system and those processes during the period during which the verification was being conducted;
(d) contain information with respect to the members of the team that conducted the verification and the role that each member performed with respect to the verification; or
(e) describe the scope of the verification.

Submission of all reports

135 A person who makes an application or submits a report that is the subject of a verification report, including in the case where the verification results in the disclaimer that is referred to in paragraph 154(d), must submit to the Minister all verification reports that they have previously obtained with respect to the application or the report.

Monitoring plan

136 (1) A person who is having an application or a report verified must prepare a monitoring plan, keep it up to date and submit it with the application or the report to the verification body.

Contents of plan

(2) The monitoring plan must contain the information referred to in Schedule 21.

Requirements Respecting Verification Bodies

Accredited body

137 The verification of an application or a report must be conducted by an accredited verification body whose accreditation is neither suspended nor revoked.

Eligibility conditions for accreditation

138 (1) A person is eligible to be accredited as a verification body by the Standards Council of Canada, the ANSI National Accreditation Board or a designated accreditation body, if the person

(a) meets the requirements set out in International Standard ISO/IEC 17029, entitled Conformity assessment — General principles and requirements for validation and verification bodies and International Standard ISO 14065, entitled General principles and requirements for bodies validating and verifying environmental information, both of which are published by the International Organization for Standardization;
(b) meets any requirements set out in Part 1 of the Methods for Verification and Certification; and
(c) employs a verification team that meets the requirements set out in International Standard ISO 14066, entitled Greenhouse gases — Competence requirements for greenhouse gas validation teams and verification teams, published by the International Organization for Standardization.

Designation of accreditation body

(2) The Minister may designate an accreditation body as a designated accreditation body referred to in subsection (1) if it is a member of the International Accreditation Forum and meets the requirements set out in ISO/IEC Standard 17011.

Independent reviewer

139 For the purposes of subclause 9.6 of the Standards referred to in paragraph 138(1)(a), the person who conducts the review must be an independent reviewer who

(a) has, at a minimum, the same competencies as those of a team leader, as set out in subclause 7.3.9 of ISO Standard 14065 referred to in that paragraph; and
(b) is an employee of the verification body.

Technical accreditation

140 (1) A verification must be conducted by a verification body that is accredited, in accordance with section 138, as a verification body that is competent in any of the following areas that are applicable to the application or the report being verified:

(a) the production, import, distribution and delivery of fossil fuels, including hydrogen that is produced from such fuels;
(b) the production, import, distribution and delivery of low-carbon-intensity fuels, other than hydrogen;
(c) the production and distribution of electricity and any transactions related to electricity;
(d) the production, import, distribution and delivery of hydrogen from renewable sources.

Definition of distribution

(2) For the purposes of subsection (1), distribution includes distribution at a fuelling station.

Team leader

141 (1) Each verification must be conducted by a team that includes a team leader who is an employee of the verification body.

Mandatory team members

(2) Each verification must be conducted by a team that includes

(a) in the case of the verification of an application or report that relates to low-carbon-intensity fuel that is produced using an eligible feedstock referred to in paragraph 46(1)(c),
- (i) a specialist in forestry or agriculture, as the case may be, who is recognized as a forestry engineer, professional forester, agricultural engineer or agrologist by
  - (A) a Canadian professional association, in the case of forestry or agriculture that occurs in Canada, or
  - (B) a relevant national authority of the country in which the forestry or agriculture occurs, in any other case, or
- (ii) a specialist in biodiversity who holds a bachelor’s degree in biology, natural sciences or environmental sciences granted by a Canadian university, or an equivalent degree granted by a university outside Canada;
(b) in the case of the verification of an application or report that relates to the sequestration of CO₂e emissions in geological land formations, whether or not those emissions are used to enhance oil recovery, a specialist in geological carbon storage who is recognized as a geologist by
- (i) a relevant Canadian professional order of geologists, in the case of sequestration in Canada, or
- (ii) a relevant national authority of the country in which the sequestration or use occurs, in any other case;
(c) in the case of the verification of an application referred to in section 130 or a carbon-intensity pathway report submitted under section 123, a specialist life-cycle assessment critical reviewer who
- (i) has knowledge of the requirements set out in ISO Standard 14040 and ISO Standard 14044 with respect to life-cycle assessment and set out in Technical Specification ISO/TS 14071, entitled Environmental management — Life cycle assessment — Critical review processes and reviewer competencies: Additional requirements and guidelines to ISO 14044:2006, published by the International Organization for Standardization,
- (ii) has knowledge of
  - (A) the Specifications for Fuel LCA Model CI Calculations and current practices with respect to the life-cycle assessment,
  - (B) the creation and review of life-cycle assessment data sets,
  - (C) the critical review of life-cycle assessments,
  - (D) all scientific disciplines relevant to life-cycle assessment,
  - (E) the relevant performance aspects of the product system that is being assessed, including environmental and technical performance aspects,
- (iii) has conducted at least two life-cycle assessments, and
- (iv) within the preceding 10 years, has conducted at least one critical review of a life-cycle assessment as an internal expert, or at least two critical reviews of a life-cycle assessment as an external expert; and
(d) in the case of the verification of a report submitted under section 125, 127 or 128, a specialist in financial accounting who
- (i) has credentials that are recognized by a competent Canadian professional order of accountants, and
- (ii) has knowledge of the accounting basis used for the entity that they are auditing and is proficient in the application of that accounting basis.

Definition of specialist

(3) For the purposes of paragraphs (2)(a) to (d), specialist means an individual with at least four years of work experience, acquired over the most recent 10 years, in the field of the specialization.

Subcontract — conditions

142 (1) Any activities that are conducted as part of the verification of an application or a report, other than those conducted by a team leader referred to in subsection 141(1) and by an independent reviewer referred to in section 139, may be subcontracted to another person if

(a) that other person has entered into a written contract with the verification body to conduct those activities;
(b) that other person has entered into a written confidentiality agreement with respect to information obtained during the conduct of those activities; and
(c) the verification body has put in place processes that permit it to evaluate the work of that other person.

Applicable requirements

(2) Subsections 141(2) and (3) and sections 145 to 153 apply in respect of any activities subcontracted to another person under subsection (1).

Outsourcing of verification — conditions

143 (1) Any activities that are carried out as part of the verification of an application or report, or any part of those activities, may be outsourced to any other verification body that is accredited in accordance with section 138 if

(a) the total number of hours of work performed by other verification bodies in carrying out the outsourced activities, in proportion to the total number of hours of work performed for the purposes of the verification, does not exceed the percentage specified in the Methods for Verification and Certification;
(b) the verification body has entered into a written contract with any verification body to which those activities are outsourced;
(c) any verification body to which those activities are outsourced is accredited as competent in the areas referred to in subsection 140(1) that are applicable to the application or report being verified;
(d) the verification report is prepared in accordance with section 133 by the verification body that is outsourcing those activities; and
(e) the verification body that is outsourcing those activities remains responsible for ensuring that the verification is carried out in full, including any outsourced activities.

Applicable requirements

(2) Section 137, subsections 138(1) and (2), section 140, subsections 141(2) and (3) and sections 145 to 153 apply in respect of any activities that are outsourced to another verification body.

Other verification report

144 A verification report that was prepared by another verification body may be relied on for the purposes of a new verification if

(a) the number of hours of work performed by the other verification body, in proportion to the total number of hours of work performed for the purposes of the new verification, does not exceed the percentage specified in the Methods for Verification and Certification;
(b) the verification body that relies on the other verification body’s verification report prepares the new verification report in accordance with section 133;
(c) the verification body that relies on the other verification body’s verification report remains responsible for the entirety of the new verification report, including the opinion referred to in section 154; and
(d) the other verification body’s verification was conducted in accordance with the applicable requirements of these Regulations.

Conflicts of interest

145 (1) A person who carries out any verification activities with respect to an application or report or who acts as an independent reviewer of a verification must be independent of

(a) the employees of the federal public administration who administer or implement these Regulations or carry out any related activities; and
(b) the person who is making the application or is required to submit the report.

Informing Minister of conflict

(2) Before a verification body begins the verification of an application or report, the person who is making the application or is required to submit the report must inform the Minister of whether a conflict of interest exists between them or any employee referred to in paragraph (1)(a) and any individual who will conduct the verification or act as the independent reviewer.

Discovery of conflict

(3) If the verification body discovers a conflict of interest, it must inform the Minister within five days after the day on which it discovers it.

Measures taken to manage conflict

(4) A person or verification body that informs the Minister of a conflict of interest under subsection (2) or (3) must provide a description of the conflict of interest and the measures that will be taken to manage it.

No work without decision by Minister

146 (1) If a conflict of interest has been discovered, the person who has the conflict of interest must not conduct any verification work and the verification must not be the subject of an independent review, unless the Minister decides that the measures taken under subsection 145(4) will effectively manage the conflict.

Decision within 20 days

(2) The Minister must inform the person who is making the application or is required to submit the report of the Minister’s decision within 20 days after the day on which the Minister is informed of the conflict of interest.

Five consecutive verifications

147 (1) An individual who acts as an independent reviewer with respect to the verification of an application or a report or who carries out any verification activities for the person who is making the application or submitting the report must not act as an independent reviewer or carry out any verification activities for that same person with respect to the same type of application or report for more than five consecutive compliance periods.

Three compliance periods

(2) An individual who, for five consecutive compliance periods, has acted as an independent reviewer with respect to the verification of an application or a report or carried out verification activities for the person who made the application or submitted the report must not act as an independent reviewer or carry out verification activities for that same person for three consecutive compliance periods beginning on the day on which the most recent verification report was submitted to the Minister.

Limitation — five compliance periods

(3) A person who has made an application or submitted a report must not act as an independent reviewer with respect to the verification of the same type of application or a report or carry out verification activities for the same type of application or report unless five compliance periods have elapsed between the day on which they made the application or submitted the report and the day on which the independent review or the verification, as the case may be, begins.

Employees of federal public administration

(4) An employee of the federal public administration who administers or implements these Regulations or carries out any related activities must not carry out any activity that is part of a verification of an application or report or an independent review of a verification, unless five compliance periods have elapsed between the day on which their employment ends and the day on which the independent review or the verification, as the case may be, begins.

Verification of reports related to applications

(5) An individual must not carry out verification activities for a report submitted under any of sections 120 to 123 or act as an independent reviewer with respect to the verification of such a report if, during the five preceding years, they carried out verification activities, or acted as the independent reviewer, with respect to an application made under subsection 80(1) or 91(1) for the approval of a carbon intensity that is referred to in the report.

Verification of certain reports

(6) An individual who carried out verification activities for a report that was submitted under section 123 or acted as an independent reviewer with respect to the verification of such a report must not, during the same compliance period, act as an independent reviewer or carry out verification activities with respect to a report that was submitted under section 120, 121 or 122 if the report was submitted by the same person who submitted the report under section 123 and it relates to the same carbon intensity.

Applicable Standards

Verification of application and report

148 (1) The verification of an application or report must be conducted by a verification body in accordance with

(a) ISO Standard 14064-3:2019, at a reasonable level of assurance; and
(b) the Methods for Verification and Certification.

Audit of financial information

(2) The verification of an application or a report that includes any financial information must include an audit of the information that is conducted in accordance with Canadian auditing standards, the primary source of which is the CPA Canada Handbook – Assurance, at a reasonable level of assurance.

Critical review

(3) The verification of an application referred to section 130 or report submitted under section 123 that includes any information relating to the life cycle of a fuel must include a critical review of the life-cycle assessment that is conducted in accordance with ISO Standard 14044.

Criteria

149 For the purposes of ISO Standard 14064-3:2019, a reference to “criteria” in subclause 3.6.10 of that Standard is to be read as

(a) in the case of an audit of financial information referred to in subsection 148(2), the International Financial Reporting Standards, published by the International Accounting Standards Board, or the Accounting Standards for Private Enterprises, published by the Accounting Standards Board;
(b) in the case of a critical review of a life-cycle assessment referred to in subsection 148(3), ISO Standard 14044; and
(c) in any other case, a reference to these Regulations and the applicable emission-reduction quantification method established under subsection 31(1) or 32(1).

Materiality quantitative threshold

150 For the purposes of subclause 5.1.7 of ISO Standard 14064-3:2019, the quantitative materiality thresholds are equal to,

(a) in the case of a carbon intensity,
- (i) 1 gCO₂e/MJ, if the absolute value of the carbon intensity is less than 20 gCO₂e/MJ,
- (ii) 5%, if the absolute value of the carbon intensity is between 20 and 100 gCO₂e/MJ, and
- (iii) 5 gCO₂e/MJ, if the absolute value of the carbon intensity is greater than 100 gCO₂e/MJ; and
(b) in any other case, 5%.

Material qualitative misstatements

151 The verification body must assess any qualitative misstatements contained in an application or report to determine if they are material qualitative misstatements.

Site visits

152 (1) In addition to meeting the requirements set out in ISO Standard 14064-3:2019 in relation to site visits, the verification of an application or a report must include,

(a) in the case of a verification of an application or a report that relates to no more than five sites, a visit by the verification body to each site at least once every five years after the first site visit; and
(b) in the case of the verification of an application or report that relates to more than five sites, a visit by the verification body to each material site if there is a high risk of misreporting and the likely cause of any misreporting is at the site and if remote evidence-gathering activities would not reduce the risk to a reasonable level.

Interpretation of ISO Standard 14064-3:2019

(2) For the purposes of ISO Standard 14064-3:2019, a reference to a “site” in subclause 3.6.13 of that Standard is to be read as a reference to

(a) the facility at which a fuel, material input or energy source is produced;
(b) the location where a CO₂e-emission-reduction project described in section 30 is carried out;
(c) the location where a feedstock used to produce a low-carbon-intensity fuel is harvested;
(d) the point of import into Canada of a low-carbon-intensity fuel;
(e) a charging station or fuelling station; or
(f) the location of a centralized computer data management system that relates to an application or report.

Aggregate quantitative misstatements

153 (1) Any quantitative misstatements in an application or report, other than those that are negligible, must be aggregated to determine their overall effect on the information in the application or report.

Negligible quantitative misstatement

(2) For the purposes of subsection (1), a quantitative misstatement is considered negligible if its value is less than 5% of the applicable materiality quantitative threshold referred to in section 150.

Material quantitative misstatement

(3) The aggregate value of quantitative misstatements in an application or a report is considered to be material when the result determined by the following formula is greater than the applicable materiality quantitative threshold referred to in section 150:

(A ÷ B) × 100: where
A: is the aggregate value of the quantitative misstatements in the application or report; and
B: is the absolute corrected value of quantitative misstatements, as determined by the verification body based on the data that, in the opinion of the verification body, should have been used to calculate those values in the application or report.

Opinion

154 The verification of an application or report must result in

(a) an unqualified opinion, if the verification body finds that the application or report does not contain any material misstatements and was prepared in accordance with these Regulations;
(b) a qualified opinion, if the verification body finds that the application or report contains one or more misstatements that are not material or finds that there is not sufficient evidence to establish whether the misstatements are material but that their effect on the application or report is not material;
(c) an adverse opinion, if the verification body finds that the application or report does not present a true and fair view in all material aspects or does not meet the criteria referred to in section 149; or
(d) the disclaimer of the verification, if the verification body finds that it does not have sufficient information or evidence to reach a decision.

Excess Compliance Credits

Export — request for cancellation and report

155 (1) If compliance credits are created by the production in Canada or import into Canada of a low-carbon-intensity fuel that is subsequently exported, the following persons must request the cancellation of the compliance credits and report the export of the fuel to the Minister:

(a) in the case where the fuel is exported by a primary supplier or registered creator, the primary supplier or registered creator who exported the fuel;
(b) in the case where the compliance credits have been the subject of a transfer request referred to in section 108 and the fuel is exported by a person who is not a primary supplier or registered creator, the primary supplier or registered creator who received the fuel from the registered creator who created those compliance credits; or
(c) in any other case, the registered creator who created the compliance credits as provisional compliance credits.

Cancellation request in report

(2) The request for the cancellation of the compliance credits must be included in the following:

(a) if the cancellation request is made by a registered creator, the report that they submit under section 122; or
(b) if the cancellation request is made by a primary supplier who is not a registered creator, the report that they submit under section 127.

Credit-creation report

(3) In the annual credit-creation report that a registered creator submits under section 120 respecting the creation of provisional compliance credits during a compliance period, the registered creator must subtract the following from those credits:

(a) the compliance credits created from the production in Canada or import into Canada of a low-carbon-intensity fuel under section 19 or 20 that is subsequently exported; or
(b) the number of compliance credits determined in accordance with subsection 88(2) or 90(2).

Re-submission of report

156 A registered creator must, within 60 days after the day on which they learn of an error made in a report that they submitted under these Regulations, other than a report submitted under section 121, if the error exceeds the significance threshold provided in the Methods for Verification and Certification, submit to the Minister

(a) an updated report in which the error has been corrected; and
(b) an updated verification report that contains a verification statement with respect to the corrected version of the report.

Notice of error

157 A registered creator must, within five days after the day on which they learn of an error made in a report that they submitted under subsection 120(1) or 122(1) that resulted in the deposit of a number of compliance credits into one of their accounts opened under section 28 that is greater than the number that should have been deposited, send a notice of that error to the Minister that indicates

(a) the name of the report that contains the error and the date on which it was submitted;
(b) the provisions of Schedule 11 or 13 to which the error relates and the nature of the error;
(c) the difference between the number of compliance credits that were deposited and the number that should have been deposited; and
(d) whether the account into which the compliance credits were deposited is a liquid-fuel-compliance-credit account opened under paragraph 28(a) or a gaseous-fuel-compliance-credit account opened under paragraph 28(b).

Suspension of excess compliance credits

158 (1) Subject to subsection (2), if the Minister has reason to believe, following the submission of a report by a registered creator or primary supplier under section 120, subsection 121(3) or sections 122 or 127, or following the submission of the form referred to in section 171, that excess compliance credits have been created, the Minister may suspend the excess compliance credits that are in any of the accounts of the registered creator or primary supplier.

Export

(2) If the Minister has reason to believe, following the submission of a report by a registered creator under section 120 or 122 or a primary supplier under section 127, that excess compliance credits have been created by the production in Canada or the import into Canada of a low-carbon-intensity fuel that is subsequently exported, the Minister may suspend the excess compliance credits that are in the account of

(a) the primary supplier or registered creator who exported the fuel, in the case where it was exported by a primary supplier or registered creator;
(b) the primary supplier or registered creator who acquired the fuel from the registered creator who created the compliance credits, in the case where it was the subject of a transfer request referred to in section 108 and was exported by a person who is not a primary supplier or registered creator; or
(c) the registered creator who created the compliance credits as provisional compliance credits, in any other case.

Suspension of equivalent compliance credits

(3) If any number of the excess compliance credits are not in the accounts referred to in subsections (1) and (2), the Minister may suspend the same number of equivalent compliance credits that are in the accounts or subsequently deposited into the accounts.

Notice of suspension

(4) When the Minister suspends, under subsection (1) or (2), excess compliance credits that are in an account or suspends, for the first time, equivalent compliance credits under subsection (3), the Minister must send a notice to the account holder.

Contents of notice

(5) The notice must include

(a) the report in which the Minister has reason to believe that an error exists;
(b) an indication of the provisions of Schedule 11, 12, 13 or 18, or the provisions of the form referred to in section 171, to which the error relates as well as the nature of the error;
(c) an indication of the account into which the excess compliance credits were deposited;
(d) an indication of the number of excess compliance credits that are to be cancelled;
(e) an indication of the number of compliance credits, if any, that are suspended under subsection (1) or (2);
(f) an indication of the number of equivalent compliance credits, if any, that are suspended under subsection (3) and the compliance period in which they were created;
(g) an indication of whether the suspended compliance credits are in a liquid-fuel-compliance-credit account opened under paragraph 28(a) or a gaseous-fuel-compliance-credit account opened under paragraph 28(b); and
(h) a statement that the Minister will suspend any additional equivalent compliance credits until the number of compliance credits that are suspended is equal to the number of excess compliance credits.

No use or transfer

(6) Beginning on the day on which the notice referred to in subsection (4) is received by the account holder and ending on the day on which the suspension is lifted, the account holder must not use suspended compliance credits to comply with the total reduction requirement or a volumetric requirement set out in subsection 6(1) or 7(1) and must not transfer suspended compliance credits under section 106 or 112.

Lifting of suspension

159 If an additional review by the Minister confirms that excess compliance credits were not created, the Minister must lift the suspension of the compliance credits.

Cancellation of excess credits

160 (1) In the following circumstances, the Minister must cancel the excess compliance credits, or the equivalent number of compliance credits, that are in an account referred to in subsection 158(1) or (2):

(a) a person makes a request referred to in subsection 155(1) for the cancellation of compliance credits;
(b) a registered creator sends a notice to the Minister in accordance with section 157; or
(c) after the Minister has suspended compliance credits under subsection 158(1) or (2), an additional review by the Minister confirms that excess compliance credits were created.

Insufficient number of equivalent credits

(2) If the number of excess compliance credits or equivalent compliance credits that are to be cancelled under subsection (1) is greater than the number of such compliance credits in the account, the Minister must send a notice to the account holder that indicates the number of compliance credits that are missing.

Obligation to balance credits

(3) The account holder must, no later than 90 days after the day on which they receive the notice,

(a) ensure that the number of equivalent compliance credits in the account is equal to the number of compliance credits that are missing; and
(b) request that the Minister cancel the equivalent compliance credits.

Cancellation of missing compliance credits

(4) On receipt of the request referred to in paragraph (3)(b), the Minister must cancel the equivalent compliance credits.

Measurement, Electronic Reporting and Records

Measurement

Requirements

161 (1) Subject to subsections (2) and (3), a person who is required by these Regulations to record any volume or quantity must determine that volume or quantity

(a) by using one or more measurement devices that meet the requirements of the Weights and Measures Act and the regulations made under that Act;
(b) in accordance with a measurement standard or method that is appropriate for the determination and cited in the Manual of Petroleum Measurement Standards, published by the American Petroleum Institute; or
(c) in accordance with any applicable emission-reduction quantification method established under subsection 31(1) or 32(1).

Non-application

(2) If there is no measurement device, standard or method referred to in subsection (1) that would allow the person to determine the volume or quantity in accordance with that subsection, the person must record the volume or quantity as accurately determined by another person who is independent of them and record the following information obtained from the other person:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the volume, expressed in cubic metres, or the quantity, expressed in kilograms for solids, in cubic metres for liquid, in cubic metres or kilograms for gas and in kilowatt-hours for electricity, and an indication of the fuel in question;
(c) the date on which and the location where the determination was made; and
(d) the measurement device, standard or method used to determine the volume or quantity.

Volumetric correction

(3) Unless otherwise specified by a provision of these Regulations, a person who determines a volume in accordance with subsection (1) must correct the volume to standard conditions. However, a person who imports into Canada a volume of fuel may correct its volume to a temperature of 15.6°C (59°F), if the person records the correction.

Biogas energy density

162 (1) A measurement of the energy density of biogas may be carried out in accordance with the fuel heat content monitoring requirements set out in section 2.D.3 of the document entitled Canada’s Greenhouse Gas Quantification Requirements / Greenhouse Gas Reporting Program, published by the Minister, and must be corrected to standard conditions.

Minimum sampling

(2) A primary supplier must conduct the sampling of biogas at least once every month.

Determination of energy density

(3) The weighted average of the energy density of biogas for a compliance period must be determined based on the measurement of energy density weighted by the volume of biogas produced.

Rounding

163 (1) Unless otherwise specified by a provision of these Regulations, a person who performs a calculation or submits a report under these Regulations must round the result of the calculation or all values in the report, as the case may be, in accordance with the rounding procedures set out in International Standard ASTM E29-22, entitled Standard Practice for Using Significant Digits in Test Data to Determine Conformance with Specifications, published by ASTM International.

Tonnes of CO₂e

(2) A primary supplier must round the result of a calculation made under section 9 to the nearest whole tonne of CO₂e or, if the result is halfway between two consecutive whole numbers, to the greater of those whole numbers.

Approved carbon intensity

(3) A registered creator, carbon-intensity contributor or foreign supplier must round a carbon intensity approved by the Minister under subsection 85(1) to the nearest whole number or, if the result is halfway between two consecutive whole numbers, to the greater of those whole numbers.

Compliance credits

(4) A number of compliance credits created under a provision of these Regulations must be rounded to the nearest whole number or, if the result is halfway between two consecutive whole numbers, to the greater of those whole numbers.

Electronic Reporting

Electronic submission — report or notice

164 (1) A person who is required by these Regulations to submit a report or send a notice to the Minister must do so electronically in the form specified by the Minister and the report or notice must bear the signature of the person’s authorized agent.

Paper report or notice

(2) If the Minister has not specified an electronic form or it is impractical for the person to submit the report or send the notice electronically because of circumstances beyond their control, the person must submit or send a paper version of the report or notice, signed by their authorized agent, in the form specified by the Minister or, if no form has been specified, in any reasonable form.

Calculation of carbon intensity

(3) A person who submits a calculation of a carbon intensity to the Minister must submit it electronically in the form specified by the Minister or, if no form has been specified, in any reasonable form.

Recording and Retention of Information

When records are made

165 Except as otherwise provided in these Regulations, any person who is required to record information must record it within 30 days after the day on which it becomes available.

Retention of information

166 (1) A person who is required by these Regulations to record information or keep it up to date, submit a report or plan or send a notice must retain a record of the information or copy of the report, plan or notice, as the case may be, as well as any supporting documents, for a period of 10 years after the day on which the information is recorded or updated, the report or plan is submitted or the notice is sent, as the case may be.

Verification or certification body

(2) A verification body or certification body must, in accordance with the Methods for Verification and Certification, retain the books and records that they have verified or certified, or a copy of those books and records, for a period of 10 years after the day on which they are verified or certified.

Emission-reduction projects

(3) A person who is required to retain any information and documents, including reports, plans, notices and supporting documents, that relate to a CO₂e-emission-reduction project referred to in paragraph 19(1)(a) or 20(a) must retain the information and documents for a period of 10 years after the day on which the carrying out of the project ceases to create compliance credits.

Location of records

(4) A foreign supplier, primary supplier, carbon-intensity contributor or registered creator who is required under subsection (1) or (3) to retain any information or documents, including supporting documents, must keep the information and documents at their principal place of business in Canada or at another place in Canada where they may be inspected, in which case the foreign supplier, primary supplier, carbon-intensity contributor or registered creator must provide the Minister with the civic address of that other place.

Exception

(5) Despite subsection (4), a registered creator who carries out a CO₂e-emission-reduction project outside Canada or a foreign supplier or carbon-intensity contributor who is outside Canada may keep the information and documents referred to in that subsection at their principal place of business outside Canada, in which case they must provide the Minister with the civic address of that place.

Records related to compliance units

167 (1) A primary supplier who, on December 31, 2022, is required by section 38 of the Renewable Fuels Regulations to keep a record, a copy of a report or notice or a supporting document that is related to a gasoline compliance unit referred to in subsection 169(1) of these Regulations or a distillate compliance unit referred to in subsection 170(1) of these Regulations must keep those documents until March 31, 2033.

Other records

(2) A primary supplier who, on December 31, 2023, is required by section 38 of the Renewable Fuels Regulations to keep a record, a copy of a report or notice or a supporting document, other than one referred to in subsection (1), must keep those documents for 10 years after the day on which they make the record or submit or send the report or notice, as the case may be.

Location of records

(3) A primary supplier who is required under subsection (1) or (2) to keep any records, copies or supporting documents must keep them at their principal place of business in Canada, or at another place in Canada where they may be inspected, in which case the primary supplier must provide the Minister with the civic address of that other place.

Information requested by Minister

168 A person who is required to record any information must, on the Minister’s request, provide a copy of the record to the Minister.

Transitional Provisions

Gasoline compliance units

169 (1) If, on April 30, 2024, a primary supplier owns gasoline compliance units under the Renewable Fuels Regulations, the number of compliance credits that is determined by the following formula must be deposited into their account that was opened under paragraph 28(a) of these Regulations:

CI_diff × (GCU × D) × 10^-9: where
CI_diff: is the difference between 59 g/MJ and the reference carbon intensity for the liquid class, as set out in item 1, column 2, of Schedule 1 to these Regulations;
GCU: is the number of gasoline compliance units that the primary supplier owned at the end of the trading period established by the Renewable Fuels Regulations for the 2022 compliance period; and
D: is 23 419 MJ/m³.

Volumetric requirement

(2) For the purposes of subsection 12(1), each compliance credit deposited under subsection (1) is deemed to have been created under paragraph 19(1)(b) or (c) by producing in Canada or importing into Canada an equivalent volume of low-carbon-intensity fuel that is ethanol.

Distillate compliance units

170 (1) If, on April 30, 2024, a primary supplier owns distillate compliance units under the Renewable Fuels Regulations, the number of compliance credits that is determined by the following formula must be deposited into their account that was opened under paragraph 28(a) of these Regulations:

CI_diff × (DCU × D) × 10^-9: where
CI_diff: is the difference between 35 g/MJ and the reference carbon intensity for the liquid class, as set out in item 1, column 2, of Schedule 1 to these Regulations;
DCU: is the number of distillate compliance units that the primary supplier owned at the end of the trading period established by the Renewable Fuels Regulations for the 2022 compliance period; and
D: is 35 057 MJ/m³.

Volumetric requirement

(2) For the purposes of subsection12(2), each compliance credit deposited under subsection (1) is deemed to have been created under paragraph 19(1)(b) or (c) by producing in Canada or importing into Canada an equivalent volume of a diesel replacement.

Request for deposit of credits

171 A primary supplier may request the deposit of compliance credits into their account in accordance with section 169 or 170 of these Regulations by providing a form to the Minister, no later than April 30, 2024, that is signed by their authorized agent and contains the following information:

(a) the number of gasoline compliance units that the primary supplier owned at the end of the trading period established by the Renewable Fuels Regulations for the 2022 compliance period;
(b) the number of distillate compliance units that the primary supplier owned at the end of the trading period established by the Renewable Fuels Regulations for the 2022 compliance period; and
(c) the number of compliance credits that will be deposited into their account that was opened under paragraph 28(a) of these Regulations.

Consequential Amendments

Renewable Fuels Regulations

172 (1) Paragraph (c) of the definition distillate compliance period in subsection 1(1) of the Renewable Fuels Regulations ^{footnote 1} is replaced by the following:

(2) Paragraph (b) of the definition gasoline compliance period in subsection 1(1) of the Regulations is replaced by the following:

(b) after December 31, 2012, each calendar year until December 31, 2022. (période de conformité visant l’essence)

Environmental Violations Administrative Monetary Penalties Regulations

173 Division 14 of Part 5 of Schedule 1 to the Environmental Violations Administrative Monetary Penalties Regulations ^{footnote 2} is repealed.

174 Schedule 1 to the Regulations is amended by adding the following after Division 17 of Part 5:

Clean Fuel Regulations

DIVISION 18
Item	Column 1 Provision	Column 2 Violation Type
1	4(3)	A
2	10(1)	A
3	10(3)	A
4	11(3)	B
5	12(3)	B
6	13(1)	B
7	13(2)	B
8	13(3)	B
9	13(4)	B
10	13(5)	B
11	14(1)	B
12	14(2)	B
13	14(3)	B
14	14(4)	B
15	15(1)	B
16	15(2)	B
17	15(3)	B
18	16(3)	B
19	18(1)	B
20	18(3)	B
21	18(4)	B
22	22(1)	A
23	23(2)	B
24	25(2)	A
25	26(1)	A
26	26(2)	A
27	26(3)	A
28	45(4)	B
29	59(1)	A
30	59(2)	A
31	95(2)	B
32	95(3)	B
33	97(2)	B
34	97(3)	B
35	99(1)	A
36	100(1)	A
37	103(1)	B
38	103(6)	B
39	103(7)	A
40	108(1)	B
41	108(2)	B
42	110(2)	B
43	112(1)	B
44	112(2)	B
45	112(3)	B
46	112(4)	B
47	112(5)	B
48	118(2)	B
49	119(1)	B
50	120(1)	B
51	120(2)	B
52	120(3)	B
53	120(4)	B
54	121(1)	B
55	121(2)	B
56	121(3)	B
57	122(1)	B
58	122(2)	B
59	123(1)	B
60	123(2)	B
61	124(1)	B
62	124(2)	B
63	125(1)	B
64	125(2)	B
65	126(1)	B
66	126(2)	B
67	127(1)	B
68	127(2)	B
69	128(1)	B
70	128(2)	B
71	130(1)	B
72	131(1)	B
73	131(3)	B
74	132	B
75	135	B
76	136(1)	B
77	136(2)	B
78	145(2)	B
79	145(4)	B
80	155(1)	B
81	155(2)	B
82	155(3)	B
83	156	B
84	157	B
85	158(6)	B
86	160(3)	B
87	161(1)	A
88	161(2)	A
89	161(3)	A
90	162(2)	A
91	163(1)	A
92	163(2)	A
93	163(3)	A
94	164(1)	A
95	164(2)	A
96	164(3)	A
97	165	A
98	166(1)	A
99	166(3)	A
100	166(4)	A
101	166(5)	A
102	167(1)	A
103	167(2)	A
104	167(3)	A
105	168	B

Repeal

Repeal

175 The Renewable Fuels Regulations ^{footnote 1} are repealed.

Coming into Force

Registration

176 (1) Subject to subsection (2), these Regulations come into force on the day on which they are registered.

September 30, 2024

(2) Sections 173 and 175 come into force on September 30, 2024.

SCHEDULE 1

(Subsections 1(1) and (2), 94(2), 95(4), 98(2), 99(3) and (4), 100(2), 101(2), 102(2), 104(2), 169(1) and 170(1))

Reference Carbon Intensity
Item	Column 1 Fuel	Column 2 Reference Carbon Intensity (gCO₂e/MJ)
Item	Column 1 Fuel	2022	2023	2024	2025	2026	2027	2028	2029	2030 and after
1	Liquid class	89.2	89.2	87.9	86.6	85.3	84.0	82.7	81.4	80.1
2	Biogas, renewable natural gas or hydrogen	67.8	67.8	67.8	67.8	67.8	67.8	67.8	67.8	67.8
3	Renewable propane or co-processed low-carbon-intensity propane	75.4	75.4	75.4	75.4	75.4	75.4	75.4	75.4	75.4

SCHEDULE 2

(Section 9 and subsections 94(2), 95(3) and (4), 96(2), 98(2), 99(3) and (4), 100(2) and 104(2) and Schedules 11, 12 and 13)

Energy Density of Fuels
Item	Column 1 Fuel or Energy Source	Column 2 Energy Density	Column 3 Measurement Unit
1	Biogas	18.57	MJ/m3
2	Renewable natural gas	38	MJ/m3
3	Compressed natural gas	38	MJ/m3
4	Hydrogen	141.8	MJ/kg
5	Ethanol	23 419	MJ/m3
6	Liquefied natural gas	55.21	MJ/kg
7	Renewable propane (in the liquid state)	25 310	MJ/m3
8	Propane (in the liquid state)	25 310	MJ/m3
9	Gasoline	34 690	MJ/m3
10	Hydrogenation-derived renewable diesel	34 921	MJ/m3
11	Biodiesel	35 183	MJ/m3
12	Low-carbon-intensity fuel suitable for use in aviation	37 400	MJ/m3
13	Diesel	38 650	MJ/m3

SCHEDULE 3

(Paragraph 1(4)(o) and subsections 10(1) and (3) and 25(1) and section 26)

Contents of Registration Report

1 The following information with respect to the primary supplier or registered creator, as the case may be:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) their business number, if any;
(c) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent; and
(d) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 The following information with respect to each facility at which the primary supplier produces gasoline or diesel:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of the facility; and
(b) whether it is gasoline or diesel that is produced at the facility.

3 The following information with respect to each province into which the primary supplier imports gasoline or diesel into Canada from outside Canada:

(a) the name of the province; and
(b) whether it is gasoline or diesel that is imported into the province by the primary supplier.

4 If the registered creator intends to create compliance credits by carrying out a CO₂e-emission-reduction project referred to in section 30 of these Regulations, the following information:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of the facility where the project is carried out or, if the project is carried out at a location other than a facility, the name, GPS coordinates to the fifth decimal place and, if any, civic address of the equipment that is used to carry out the project;
(b) the type of any fuel, material input or energy source that is used to carry out the project if an application for the approval of the carbon intensity of that fuel, material input or energy source is required by the applicable emission-reduction quantification method established under subsection 31(1) or 32(1) of these Regulations; and
(c) if the project is one described in paragraph 30(d) of these Regulations, for each co-processed low-carbon intensity fuel that is imported into Canada for use as a fuel in Canada, whether as a neat fuel or as part of a blend, its type and the name of the province into which the co-processed low carbon intensity fuel is imported.

5 If the registered creator intends to create compliance credits by importing into Canada a low-carbon-intensity fuel for use in Canada as a fuel, whether as neat fuel or as part of a blend, the following information for each province into which the registered creator intends to import fuel:

(a) the name of the province; and
(b) the type of fuel that will be imported.

6 If the registered creator intends to create compliance credits by producing a low-carbon-intensity fuel for use in Canada as a fuel, whether as neat fuel or as part of a blend, the following information with respect to each facility at which the fuel will be produced:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of the facility; and
(b) the type of fuel produced at the facility.

7 If the registered creator intends to create compliance credits by producing biogas for use in equipment to produce electricity, the following information:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each facility at which the biogas will be produced; and
(b) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each facility at which the electricity will be produced.

8 If the registered creator intends to create compliance credits by displacing the use in Canada of a quantity of fuel in the liquid class as a fuel for a vehicle with the use in Canada of a quantity of propane, renewable propane, co-processed low-carbon-intensity propane, compressed natural gas, compressed renewable natural gas, liquefied natural gas or liquefied renewable natural gas as a fuel for a vehicle, the following information with respect to each fuelling station that supplied the fuel that displaces the fuel in the liquid class:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of the fuelling station; and
(b) the type of each fuel that will be supplied at the fuelling station for which the registered creator intends to create compliance credits.

9 If the registered creator is a charging-network operator and intends to create compliance credits by displacing the use in Canada of a quantity of fuel in the liquid class as a fuel for a vehicle with the use in Canada of electricity as an energy source supplied to an electric vehicle by a charging station that is intended primarily for use by the occupants of a private dwelling-place, with respect to each charging station at which the electricity will be supplied, the name of the province in which it is located.

10 If the registered creator is a charging-network operator and intends to create compliance credits by displacing the use in Canada of a quantity of fuel in the liquid class as a fuel for a vehicle with the use in Canada of electricity as an energy source supplied to an electric vehicle by a charging station that is intended primarily for use by the public, with respect to each charging station at which the electricity will be supplied, the name of the province in which it is located.

11 If the registered creator is a charging-site host and intends to create compliance credits by displacing the use in Canada of a quantity of fuel in the liquid class as a fuel for a vehicle with the use in Canada of electricity as an energy source supplied to an electric vehicle by a charging station other than a charging station described in sections 9 and 10 of this Schedule, with respect to each charging station at which the electricity will be supplied, the name of the province in which it is located.

12 If the registered creator intends to create compliance credits by displacing the use in Canada of a quantity of fuel in the liquid class as fuel for a vehicle with the use in Canada of a quantity of hydrogen as an energy source for a hydrogen fuel cell vehicle, the name, GPS coordinates to the fifth decimal place and, if any, civic address of each hydrogen fuelling station at which the hydrogen will be supplied.

SCHEDULE 4

(Paragraphs 34(2)(a), 37(2)(a) and (c), 38(2)(a) and 40(2)(a) and (c))

Contents of Application for Recognition of CO₂e-Emission-Reduction Project

1 The following information with respect to the applicant:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of the authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 A description of the project that includes

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of any facility at which the project is to be carried out;
(b) the name, serial number, GPS coordinates to the fifth decimal place and, if any, civic address of any equipment with which the project is to be carried out;
(c) the duration of the project and the anticipated start- and end dates for carrying out the project;
(d) the information required by the emission-reduction quantification method established under subsection 31(1) or 32(1), whichever is applicable to the project, including an explanation of how the project is anticipated to lower the carbon intensity of a fuel in the liquid or gaseous class and any supporting documents;
(e) in the case of an application for the recognition of a CO₂e-emission-reduction project using a generic emission-reduction quantification method established under subsection 31(1) of these Regulations,
- (i) the specified activities that would have been carried out if not for the implementation of the project and the CO₂e emissions that would have resulted from those activities, as well as the greenhouse gas sources and sinks that have been selected by the applicant to determine those CO₂e emissions and a rationale for the selection of those greenhouse gas sources and sinks;
- (ii) the greenhouse gas sources and sinks that have been selected by the applicant and are relevant to the project and a rationale for the selection of those greenhouse gas sources and sinks;
(f) the annual reduction in the quantity of CO₂e that is anticipated to result from the project, expressed in tonnes of CO₂e, including any relevant data and calculations and any technical documents that are used in support of those calculations; and
(g) an indication of the regulatory regime and the federal or provincial laws under which the project operates and any federal or provincial laws and programs under which it receives funding.

SCHEDULE 5

(Paragraphs 62(2)(c) and (d))

Contents of Certification Scheme Operation Report

1 The following information with respect to the person who is the scheme owner:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of the authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 The following information regarding the members of the certification scheme:

(a) the number of current members;
(b) the number of new members;
(c) the number of suspended members; and
(d) the number of members whose participation in the scheme has been terminated, as well as the reasons for the termination.

3 The following information regarding the operation of the certification scheme:

(a) the number of years remaining in the approval period of the scheme;
(b) the changes made to the scope of the scheme;
(c) the quantity of certified feedstock, by type and country of origin;
(d) the number of audits conducted, by members of the scheme and by type of feedstock;
(e) the number of situations of non-conformity detected, by members of the scheme;
(f) the number of situations of non-conformity detected, by type and degree of severity; and
(g) the number of cases of fraud or irregularities detected.

4 The following information regarding the design and operation of the management system of the certification scheme:

(a) a description of stakeholder involvement during the drafting and reviewing of the scheme as well as the responses given to any contributions by stakeholders;
(b) the criteria for the recognition and accreditation of certification bodies;
(c) the qualification requirements for auditors, according to their role;
(d) the impartiality requirements for certification bodies and auditors;
(e) the procedures for detecting and addressing non-conformity;
(f) the procedures for monitoring the certification bodies;
(g) the procedures for preventing fraud, including detection and resolution, and follow-up procedures for suspected fraud and other irregularities;
(h) a description of any complaints lodged against the certification scheme and the manner in which they were resolved; and
(i) an analysis of the scheme’s requirements, compared to industry’s actual best practices.

5 A description of the procedures that permit an assessment of the availability of the following documents:

(a) a translation of the certification scheme’s requirements and procedures in the common language of the country or region from which any certified feedstock originates;
(b) a list of certified feedstock producers and their corresponding certificates; and
(c) any auditor reports.

6 A description of any improvements made by the scheme owner to the certification scheme and, if the scheme owner has any recommendations regarding any matter related to the regulatory regime, those recommendations.

SCHEDULE 6

(Paragraphs 75(1)(a) and (b), (6)(a) and (7)(a) and 96(4)(a))

Default Carbon Intensity

1 The default carbon intensity is

(a) 80 gCO₂e/MJ for the years 2022 and 2023;
(b) 79 gCO₂e/MJ for the year 2024;
(c) 78 gCO₂e/MJ for the year 2025;
(d) 77 gCO₂e/MJ for the year 2026;
(e) 76 gCO₂e/MJ for the year 2027;
(f) 74 gCO₂e/MJ for the year 2028;
(g) 73 gCO₂e/MJ for the year 2029; and
(h) 72 gCO₂e/MJ for the year 2030 and the following years.

2 The quantity of CO₂e that is associated with the extraction or production, as the case may be, of a feedstock is

(a) 0 gCO₂e/MJ for a fuel or material input produced from a feedstock that is derived from one of the following:
- (i) forest biomass derived from fire prevention and protection activities or from clearing activities that are not related to harvesting, such as infrastructure installation, pest and disease control and road maintenance,
- (ii) crop residues or damaged crops,
- (iii) secondary forest residues that are by-products of industrial wood-processing operations,
- (iv) used or inedible organics from a residential area, a retail store, a restaurant, a caterer or a food processing plant,
- (v) used fat and used vegetable oils,
- (vi) used animal litter,
- (vii) animal materials, including manure,
- (viii) industrial effluents,
- (iv) municipal wastewater, and
- (x) used construction materials and demolition materials,
- (xi) residues that are directly generated by agriculture, aquaculture and fisheries, but not residues from related industries or from processing,
- (xii) water,
- (xiii) waste from a waste processing facility that produces biogas, and
- (xiv) carbon dioxide that has been captured from the atmosphere;
(b) 15 gCO₂e/MJ for a fuel or material input produced from a feedstock derived from crops grown solely for energy production and that are not traditionally grown for food and feed purposes;
(c) 20 gCO₂e/MJ for a fuel or material input produced from a feedstock that is an oil extracted from oilseed crops; and
(d) 35 gCO₂e/MJ for a fuel or material input produced from any other feedstock.

3 The quantity of CO₂e that is released during the production of the fuel or material input from the feedstock, the transportation of the feedstock and intermediary products used to produce the fuel or material input and the distribution of the fuel or material input to end users is

(a) 13 gCO₂e/MJ for a fuel or material input that is produced at a facility that
- (i) uses thermal energy and electricity where more than 50% of that energy is from non-fossil sources, electricity with a carbon intensity of less than 100 gCO₂e/MJ, hydrogen from renewable sources, hydrogen from natural gas with carbon capture and storage or a mix of those sources, and
- (ii) does not use liquid or solid fossil fuels in stationary applications;
(b) 30 gCO₂e/MJ for a fuel or material input that is produced at a facility, other than one described in subparagraph (a)(i), that does not use liquid or solid fossil fuels in stationary application; and
(c) 65 gCO₂e/MJ for a fuel or material input that is produced at any other fuel production facility.

4 The quantity of CO₂e t that is released during the compression or liquefaction process of the fuel material input is

(a) 12 gCO₂e/MJ for compressed hydrogen that is supplied by a hydrogen fuelling station;
(b) 60 gCO₂e/MJ for liquefied hydrogen that is supplied by a hydrogen fuelling station; and
(c) 0 gCO₂e/MJ for all other fuels, including hydrogen referred to in section 95 of these Regulations that is supplied for use as a fuel.

5 The quantity of CO₂e that is associated with the production of electricity used during the production of the fuel or material input is

(a) 25 gCO₂e/MJ for hydrogen produced from electrolysis using electricity with a carbon intensity of 50 g/MJ or less;
(b) 150 gCO₂e/MJ for any other hydrogen produced from electrolysis; and
(c) 0 gCO₂e/MJ for any other fuel.

6 The quantity of CO₂e that is released during the transportation of the feedstock and intermediary products used to produce the fuel or material input and the distribution of the fuel or material input to end users, in the case of a total transportation distance of no less than 1500 km, is

(a) 0 gCO₂e/MJ for a fuel or material input for which the sum of the distance between the site where the feedstock was extracted, harvested or produced and the facility where the fuel or material input was produced and the distance between that facility and the location of final distribution to end users is less than 1500 km; and
(b) 4 gCO₂e/MJ for any other fuel or material input.

7 The quantity of CO₂e that is released during the combustion of the fuel or the use of the material input, per megajoule of energy produced, is

(a) 0 gCO₂e/MJ for hydrogen or carbon dioxide derived from atmospheric carbon dioxide;
(b) 1 gCO₂e/MJ for biogas or renewable natural gas;
(c) 2 gCO₂e/MJ for ethanol or a fuel derived from biomass other than biodiesel;
(d) 3 gCO₂e/MJ for biodiesel; and
(e) 72 gCO₂e/MJ for any other fuel.

8 The carbon intensity of fossil fuels and energy sources is equal to

(a) 110 gCO₂e/MJ for compressed hydrogen;
(b) 150 gCO₂e/MJ for liquefied hydrogen;
(c) 76 gCO₂e/MJ for propane;
(d) 68 gCO₂e/MJ for natural gas;
(e) 113 gCO₂e/MJ for liquefied natural gas; and
(f) 72 gCO₂e/MJ for compressed natural gas.

9 The carbon intensity of electricity for a province is

(a) 14 gCO₂e/MJ in Ontario;
(b) 5 gCO₂e/MJ in Quebec;
(c) 224 gCO₂e/MJ in Nova Scotia;
(d) 89 gCO₂e/MJ in New Brunswick;
(e) 7 gCO₂e/MJ in Manitoba;
(f) 11 gCO₂e/MJ in British Columbia;
(g) 2 gCO₂e/MJ in Prince Edward Island;
(h) 237 gCO₂e/MJ in Saskatchewan;
(i) 218 gCO₂e/MJ in Alberta;
(j) 16 gCO₂e/MJ in Newfoundland and Labrador;
(k) 30 gCO₂e/MJ in Yukon;
(l) 71 gCO₂e/MJ in the Northwest Territories; and
(m) 313 gCO₂e/MJ in Nunavut.

SCHEDULE 7

(Subsection 81(2))

Contents of Application for Approval of New Pathway

1 The following information with respect to the applicant:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of the authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 The name, GPS coordinates to the fifth decimal place and, if any, civic address of the facility where the fuel, energy source or material input was produced.

3 The type of fuel, type of energy source or type of material input that is renewable natural gas, biogas, renewable propane or hydrogen for which the determination was made.

4 The type of feedstock used to produce the fuel or material input and the region where the feedstock was extracted, harvested or produced, as the case may be.

5 The rationale for the application and a demonstration that one of the criteria set out in the Specifications for Fuel LCA Model CI Calculations is met.

6 The type of carbon intensity that will be determined by the new pathway, either “cradle-to-gate” or “cradle-to-grave” as defined in the Specifications for Fuel LCA Model CI Calculations.

7 A description of any change made to unit processes, modelling parameters or background data sets from the Fuel LCA Model and the rationale for the change that is consistent with ISO Standard 14040 and ISO Standard 14044 and the Specifications for Fuel LCA Model CI Calculations.

8 A description of the new pathway that is consistent with ISO Standard 14040 and ISO Standard 14044 and the Specifications for Fuel LCA Model CI Calculations.

9 A description of the data sources and the methods used to collect and determine the data that are entered into a data workbook.

10 A description of any calculations performed on the data in the data workbook, including the addition of background data used in the calculations.

11 A copy of the data workbook, including any calculations performed on the data, that is consistent with the Specifications for Fuel LCA Model CI Calculations and used to determine the data that are inputted into the Fuel LCA Model.

12 Any supporting documentation required by the Specifications for Fuel LCA Model CI Calculations.

13 A copy of the new pathway from the Fuel LCA Model with or without input data.

14 The information listed in any applicable emission-reduction quantification method established under subsection 31(1) or 32(1) of these Regulations.

15 If the new pathway includes a carbon intensity transferred from a carbon-intensity contributor, foreign supplier or registered creator, the following information:

(a) the name, civic address, postal address, telephone number and, if any, email address of the carbon-intensity contributor, foreign supplier or registered creator;
(b) the type of low-carbon-intensity fuel, material input or energy source provided by the carbon-intensity contributor, foreign supplier or registered creator; and
(c) if the carbon intensity of the low-carbon-intensity fuel, material input or energy source referred to in paragraph (b) was determined using a carbon intensity approved by the Minister, the approved carbon intensity and any alphanumeric identifier assigned to it under subsection 85(2) of these Regulations.

SCHEDULE 8

(Sections 82 to 84)

Contents of Application for Approval of Carbon Intensity

1 The following information, if the application relates to a low-carbon-intensity fuel or material input:

(a) the name, civic address, postal address, telephone number and, if any, email address of the applicant;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of the applicant’s authorized agent;
(c) the name, title, civic address, postal address, telephone number and, if any, email address of the applicant’s contact person, unless the contact person is the authorized agent;
(d) the name, GPS coordinates to the fifth decimal place and, if any, civic address of the facility where the fuel or material input was produced;
(e) the type of fuel or material input for which the determination was made;
(f) the carbon intensity determined for the fuel or material input, rounded to the nearest hundredth of a gram of CO₂e per megajoule;
(g) if an additional value referred to in subsection 80(2) of these Regulations has been added to the carbon intensity referred to in paragraph (f), the additional value and the sum of the additional value and the carbon intensity value, rounded to the nearest hundredth of a gram of CO₂e per megajoule;
(h) the type of feedstock used to produce the fuel or material input;
(i) if the feedstock was extracted, harvested or produced, the region where the feedstock was extracted, harvested or produced, as the case may be; and
(j) a diagram that shows the process flow used to produce the fuel or material input.

2 In the case of a carbon intensity determined in accordance with paragraph 75(1)(b) of these Regulations, the following information:

(a) the type of thermal energy and the source of electricity that is used at the production facility;
(b) if the application indicates that the variable CI_p that is referred to in paragraph 75(1)(b) of these Regulations has a value of 13 g/MJ, the percentage of the electrical and thermal energy used at the production facility that is from non-fossil sources, electricity with a carbon intensity of less than 100 g/MJ, hydrogen from renewable sources, hydrogen from natural gas with carbon capture and storage or a mix of those sources, and the estimated quantity of thermal energy and electricity from each source; and
(c) if the application indicates that the variable CI_td that is referred to in paragraph 75(1)(b) of these Regulations has a value of 0 g/MJ, the distance between the site where the feedstock was extracted, harvested or produced and the production facility where the fuel or material input was produced and the distance between that facility and the final location where the fuel is distributed to end users.

3 In the case of a carbon intensity determined in accordance with section 76 or 77 of these Regulations, the following information:

(a) an indication of whether the pathway from the Fuel LCA Model used for that determination is an existing pathway, or a new pathway;
(b) if the pathway from the Fuel LCA Model used for that determination is a new pathway, the alphanumeric identifier assigned to the approved pathway under subsection 81(4) of these Regulations;
(c) a copy of the pathway from the Fuel LCA Model that was used for that determination, including all data that are input into the Fuel LCA Model and all results that are obtained from it;
(d) the type of carbon intensity that will be determined, either “cradle-to-gate” or “cradle-to-grave” as defined in the Specifications for Fuel LCA Model CI Calculations;
(e) a description of the data sources and the methods used to collect and determine the data that are entered into a data workbook;
(f) a copy of the data workbook, including any calculations performed on the data, that is consistent with the Specifications for Fuel LCA Model CI Calculations and used to determine the data that are inputted into the Fuel LCA Model;
(g) any supporting documentation required by the Specifications for Fuel LCA Model CI Calculations; and
(h) the information listed in any applicable emissions- reduction quantification method established under subsection 31(1) or 32(1) of these Regulations.

4 In the case of a carbon intensity determined in accordance with section 78 of these Regulations, the following information:

(a) the name, civic address, postal address, telephone number and, if any, email address of the applicant;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of the applicant’s authorized agent;
(c) the name, title, civic address, postal address, telephone number and, if any, email address of the applicant’s contact person, unless the contact person is the authorized agent;
(d) the GPS coordinates to the fifth decimal place and, if any, civic address of each fuelling station that supplies the fuel;
(e) the GPS coordinates to the fifth decimal place and, if any, civic address of any location, other than a fuelling station, where propane, renewable propane, co-processed low-carbon-intensity propane, natural gas, renewable natural gas or hydrogen is liquefied or compressed for use in a fuelling station;
(f) the type of any fossil fuel supplied to vehicles at the fuelling stations referred to in paragraph (d);
(g) the type of any low-carbon-intensity fuel that is supplied to vehicles at the fuelling stations referred to in paragraph (d);
(h) the carbon intensity determined for the fuel, rounded to the nearest hundredth of a gram of CO₂e per megajoule;
(i) if an additional value referred to in subsection 80(2) of these Regulations has been added to the carbon intensity referred to in paragraph (h), the additional value and the sum of the additional value and the carbon intensity value, rounded to the nearest hundredth of a gram of CO₂e per megajoule;
(j) a diagram of each compression or liquefaction process;
(k) an indication of the option used for the determination of the carbon intensity of the fuel referred to in paragraph (e) in relation to the pathway from the Fuel LCA Model, whether it is an existing pathway or a new pathway and, in the case of a new pathway, the alphanumeric identifier assigned to it under subsection 81(4) of these Regulations;
(l) a copy of the pathway from the Fuel LCA Model that was used for the determination of the carbon intensity, including all data that are input into the Fuel LCA Model and all results that are obtained from it;
(m) a description of the data sources and the methods used to collect and determine the data that are entered into a data workbook;
(n) a copy of the data workbook, including any calculations performed on the data, that is consistent with the Specifications for Fuel LCA Model CI Calculations and used to determine the data that are inputted into the Fuel LCA Model;
(o) any supporting documentation required by the Specifications for Fuel LCA Model CI Calculations; and
(p) the information listed in any applicable emission-reduction quantification method established under subsection 31(1) or 32(1) of these Regulations.

5 In the case of a carbon intensity determined in accordance with section 79 of these Regulations, the following information:

(a) the name, civic address, postal address, telephone number and, if any, email address of the applicant;
(b) the name, title, civic address, postal address, telephone number and, if any, the email address of the applicant’s authorized agent;
(c) the name, title, civic address, postal address, telephone number and, if any, email address of the applicant’s contact person, unless the contact person is the authorized agent;
(d) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each facility or location where there is one or more charging stations or fuelling stations to which the electricity was supplied;
(e) the GPS coordinates to the fifth decimal place and, if any, civic address of each site where the electricity was produced if that site is different from the facility or location referred to in paragraph (d);
(f) the carbon intensity determined for the electricity, rounded to the nearest hundredth of a gram of CO₂e per megajoule;
(g) if an additional value referred to in subsection 80(2) of these Regulations has been added to the carbon intensity referred to in paragraph (f), the additional value and the sum of the additional value and the carbon intensity value, rounded to the nearest hundredth of a gram of CO₂e per megajoule;
(h) the source of electricity supplied to charging stations, facilities or fuelling stations;
(i) an indication of whether the pathway from the Fuel LCA Model used for the determination of the carbon intensity is an existing pathway or a new pathway and, in the case of a new pathway, the alphanumeric identifier assigned to it under subsection 81(4) of these Regulations;
(j) a copy of the pathway from the Fuel LCA Model that was used for that determination, including all data that are input into the Fuel LCA Model and all results that are obtained from it;
(k) a description of the data sources and the methods used to collect and determine the data that are entered into a data workbook;
(l) a copy of the data workbook, including any calculations performed on the data, that is consistent with the Specifications for Fuel LCA Model CI Calculations and used to determine the data that are inputted into the Fuel LCA Model;
(m) any supporting documentation required by the Specifications for Fuel LCA Model CI Calculations; and
(n) the information listed in any applicable emission-reduction quantification method established under subsection 31(1) or 32(1) of these Regulations.

6 If the determination of the carbon intensity includes a carbon intensity that was transferred from a carbon-intensity contributor, foreign supplier or registered creator and that was approved under subsection 85(1) of these Regulations, the following information:

(a) the name, civic address, postal address, telephone number and, if any, email address, of the carbon-intensity contributor, foreign supplier or registered creator;
(b) the type of low-carbon-intensity fuel, material input or energy source provided by the carbon-intensity contributor, foreign supplier or registered creator; and
(c) the approved carbon intensity of the low-carbon-intensity fuel, material input or energy source referred to in paragraph (b) and the alphanumeric identifier assigned to it under section 85(2) of these Regulations.

SCHEDULE 9

(Subsection 114(2))

Contents of Application for Registration of emission-reduction Funding Program

1 The following information with respect to the person who administers the emission-reduction funding program:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent;
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent;
(d) their business number, if any;
(e) the Internet address of their website;
(f) their constituting documents, including any articles of incorporation, articles of amendments, partnership agreements or declaration of trust;
(g) their organizational chart;
(h) the names and titles of the members of their Board of Directors, if any;
(i) the details of their financial and management control system;
(j) the details of their management practices; and
(k) the details of their information system.

2 The following information with respect to the emission-reduction funding program:

(a) its description;
(b) a list of the types of projects that are eligible to be funded by the program;
(c) the estimated duration of the projects that will be funded;
(d) the policies, criteria, procedures or project-specific milestones according to which the projects will be funded;
(e) the policy on conflicts of interest;
(f) if the emission-reduction funding program has been operational for three or more years, the last three financial audits; and
(g) if the emission-reduction funding program has been operational for less than three years, information on the financial stability and resources required for its operations.

SCHEDULE 10

(Paragraphs 114(2)(b), 115(2)(c) and 116(c) and (d))

Contents of Emission-Reduction Funding Program Report

1 The following information with respect to the person who administers the emission-reduction funding program:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 The following information with respect to each project funded by the registered emission-reduction funding program:

(a) its name;
(b) its description;
(c) the amount of funding it received;
(d) its location;
(e) the status of its milestones and its estimated completion dates;
(f) the actual or anticipated reduction in the quantity of CO₂e from the project and the date on which the reduction was achieved or is estimated to be achieved; and
(g) a description of the methodology used to calculate the reduction that was achieved and any documentation that provides evidence for the inputs used in that calculation.

3 A copy of the financial audit referred to in paragraph 116(b) of these Regulations.

SCHEDULE 11

(Subsection 120(2) and paragraphs 157(b) and 158(5)(b))

Contents of Annual Credit-Creation Report

1 The following information with respect to the registered creator:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 The following information with respect to each CO₂e-emission-reduction project carried out by the registered creator or a person with whom they have entered into an agreement under section 21 of these Regulations:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of the facility where the project is carried out or, if the project is carried out at a location other than a facility, the name, GPS coordinates to the fifth decimal place and, if any, civic address of the equipment that is used to carry out the project, as specified by the emission-reduction quantification method established under subsection 31(1) or 32(1) of these Regulations that is applicable to the project;
(b) the alphanumeric identifier assigned to the project;
(c) the number of provisional compliance credits created in respect of the liquid class during the compliance period;
(d) an indication of whether compliance credits have been determined using a generic emission-reduction quantification method established under subsection 31(1) of these Regulations that is applicable to the project;
(e) the information required by the emissionreduction quantification method established under subsection 31(1) or 32(1) of these Regulations;
(f) if there are any changes in the information contained in the application referred to in subsection 34(2), 37(2), 38(2), 40(2) or 42(2) of these Regulations, the updated information, other than
- (i) any information referred to in paragraph 34(2)(c), 37(2)(b), 38(2)(c) or 40(2)(b) of these Regulations, and
- (ii) any information that is specified in the applicable emission-reduction quantification method as information that cannot be changed; and
(g) if the project is one referred to in paragraph 30(d) of these Regulations, for each co-processed low-carbon-intensity fuel,
- (i) the type of each co-processed low-carbon-intensity fuel that is produced,
- (ii) an indication of whether the fuel is a gasoline replacement or diesel replacement,
- (iii) the carbon intensity of the fuel, whether it is the default carbon intensity determined in accordance with the emission-reduction quantification method that is applicable to the project or the carbon intensity that approved under subsection 85(1) of these Regulations and any alphanumeric identifier assigned to the carbon intensity under subsection 85(2) of these Regulations,
- (iv) the number of provisional compliance credits that have been created by the production of the fuel in accordance with the emission-reduction quantification method that is applicable to the project, and
- (v) an indication of whether the compliance credits have been created in respect of the liquid or gaseous class.

3 If the registered creator, or a person with whom they have entered into an agreement under section 21 of these Regulations, is the owner or operator of a fuelling station referred to in subsection 98(1) of these Regulations, the following information with respect to each propane, compressed natural gas or liquefied natural gas that is supplied at that fuelling station:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each fuelling station where fuel was supplied to vehicles;
(b) for each fuelling station referred to in paragraph (a),
- (i) the type of fuel for which the compliance credits are created,
- (ii) the quantity of the fuel referred to in subparagraph (i),
- (iii) the total quantity of fuel that contains the fuel referred to in subparagraph (i) that is supplied to vehicles at that fuelling station, as measured by a meter and expressed in cubic metres of fuel in the liquid state, in cubic metres or in kilograms, as the case may be,
- (iv) the total quantity of renewable propane, co-processed low-carbon-intensity propane or renewable natural gas supplied to vehicles, determined from the supporting documents referred to in subsection 99(2) of these Regulations and expressed in cubic metres of fuel in the liquid state, in cubic metres or in kilograms, as the case may be;
(c) for each fuel type referred to in subparagraph (b)(i),
- (i) the carbon intensity of propane, compressed natural gas or liquefied natural gas that is determined in accordance with subsection 75(6) of these Regulations, that is approved under subsection 85(1) of these Regulations or that is the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1) of these Regulations, as the case may be, and
- (ii) the energy density of the propane or compressed natural gas, expressed in megajoules per cubic metre, or the energy density of liquefied natural gas, expressed in megajoules per kilogram, as the case may be, as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations, at the election of the registered creator; and
(d) the number of provisional compliance credits created by the supply of fuel under subsection 98(1) of these Regulations.

4 If the registered creator, or a person with whom they have entered into an agreement under section 21 of these Regulations, is the owner or operator of a fuelling station referred to in subsection 99(1) of these Regulations, the following information with respect to each renewable propane, co-processed low-carbon intensity propane, compressed renewable natural gas or liquefied renewable natural gas that is supplied at that fuelling station:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each fuelling station where fuel was supplied to vehicles;
(b) for each fuelling station referred to in paragraph (a), the types of fuel that are supplied to vehicles and that are used to create compliance credits;
(c) for each type of fuel referred to in paragraph (b),
- (i) the carbon intensity of compressed natural gas, liquefied natural gas or propane that is determined in accordance with subsection 75(6) of these Regulations, that is approved under subsection 85(1) of these Regulations or that is the actual carbon intensity specified in the carbon-intensity pathway-report referred to in subsection 123(1) of these Regulations, as the case may be, and any alphanumeric identifier assigned to it under subsection 85(2) of these Regulations,
- (ii) its energy density, expressed in megajoules per cubic metre or megajoules per kilogram, as the case may be, as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations, at the election of the registered creator,
- (iii) the quantity that is supplied to vehicles at each fuelling station, expressed in cubic metres of fuel in the liquid state in the case of renewable propane or co-processed low-carbon-intensity propane, expressed in cubic metres in the case of compressed renewable natural gas and expressed in kilograms in the case of liquefied renewable natural gas, and
- (iv) the name of the person from whom that type of fuel was purchased; and
(d) the number of provisional compliance credits created under subsection 99(1) of these Regulations for renewable propane, co-processed low-carbon-intensity propane, compressed renewable natural gas or liquefied renewable natural gas, as the case may be.

5 If the registered creator, or a person with whom they have entered into an agreement under section 21 of these Regulations, is a charging-site host referred to in subsection 101(1) of these Regulations, the following information with respect to the electricity that is supplied to electric vehicles:

(a) for each province where the electricity is supplied to electric vehicles,
- (i) the carbon intensity of the electricity that is determined in accordance with subsection 75(7) of these Regulations, that is approved under subsection 85(1) of these Regulations or that is the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1) of these Regulations, as the case may be, and
- (ii) the serial number and the name or identifier of each charging station in the province;
(b) for each charging station referred to in subparagraph (a)(ii) that is not accessible to marine vessels,
- (i) its GPS coordinates to the fifth decimal place and, if any, its civic address,
- (ii) the energy efficiency ratio for light-duty electric vehicles on the January 1 of the compliance period, as set out in the Specifications for Fuel LCA Model CI Calculations, or an energy efficiency ratio of 2.5, at the election of the registered creator,
- (iii) the energy efficiency ratio for electric vehicles, other than those referred to in subparagraph (ii), on the January 1 of the compliance period, as set out in the Specifications for Fuel LCA Model CI Calculations, or an energy efficiency ratio of 2.5, at the election of the registered creator, and
- (iv) the quantities of electricity that are supplied to the electric vehicles referred to in subparagraphs (ii) and (iii);
(c) for each charging station referred to in subparagraph (a)(ii) that is accessible to marine vessels,
- (i) its GPS coordinates to the fifth decimal place and, if any, its civic address,
- (ii) the energy efficiency ratio for electric marine vessels t on the January 1 of the compliance period, as set out in the Specifications for Fuel LCA Model CI Calculations, or an energy efficiency ratio of 2.5, at the election of the registered creator, and
- (iii) the quantity of electricity that is supplied to electric marine vessels; and
(d) the number of provisional compliance credits created under subsection 101(1) of these Regulations for the supply of electricity to electric vehicles.

6 If the registered creator, or a person with whom they have entered into an agreement under section 21 of these Regulations, is the operator of a charging network referred to in subsection 102(1) of these Regulations, the following information with respect to the electricity that is supplied to electric vehicles:

(a) for each province in which the electricity is supplied to electric vehicles,
- (i) the carbon intensity of the electricity that is determined in accordance with subsection 75(7) of these Regulations, that is approved under subsection 85(1) of these Regulations or that is the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1) of these Regulations, as the case may be, and
- (ii) the total quantity of electricity of a specified carbon intensity that is supplied to electric vehicles in the province, expressed in kilowatt hours;
(b) the energy efficiency ratio for light-duty electric vehicles on the January 1 of the compliance period, as set out in the Specifications for Fuel LCA Model CI Calculations, or an energy efficiency ratio of 2.5, at the election of the registered creator;
(c) for each charging station that is intended primarily for use by the occupants of a private dwelling-place,
- (i) the province in which it is located and its serial number, and
- (ii) the quantity of electricity of a specified carbon intensity that is supplied to electric vehicles by that charging station, expressed in kilowatt hours;
(d) for each charging station that is intended primarily for use by the public,
- (i) the province in which it is located, its GPS coordinates to the fifth decimal place and, if any, its name or identifier, civic address and serial number, and
- (ii) the quantity of electricity of a specified carbon intensity that is supplied to electric vehicles by that charging station, expressed in kilowatt hours; and
(e) the number of provisional compliance credits created under subsection 102(1) of these Regulations by the supply of electricity to electric vehicles.

7 If the registered creator, or a person with whom they have entered into an agreement under section 21 of these Regulations, is the owner or operator of a hydrogen fuelling station, the following information with respect to the hydrogen supplied by those stations for use in Canada as an energy source for hydrogen fuel cell vehicles in accordance with paragraph 104(1)(a) of these Regulations:

(a) for each hydrogen fuelling station,
- (i) its name, GPS coordinates to the fifth decimal place and, if any, its civic address, and
- (ii) the quantity of hydrogen, expressed in kilograms, that is supplied to each class of hydrogen fuel cell vehicles listed in the Specifications for Fuel LCA Model CI Calculations;
(b) the carbon intensity of the hydrogen supplied to the vehicles referred to in subparagraph (a)(ii) that is the default carbon intensity referred to in paragraph 75(1)(a) of these Regulations or determined in accordance with paragraph 75(1)(b) or subsection 75(6) of these Regulations, that is approved under subsection 85(1) of these Regulations or that is the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1) of these Regulations, as the case may be, and any alphanumeric identifier assigned to the carbon intensity;
(c) if feedstock is used to produce the hydrogen, the type of that feedstock and the region where it was extracted, harvested or produced;
(d) if eligible feedstock is used to produce the hydrogen, the maximum quantity of hydrogen, determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres, that is produced using the eligible feedstock in order to create compliance credits under paragraph 104(1)(a) of these Regulations and that is supplied to vehicles at each fuelling station; and
(e) the number of provisional compliance credits created under paragraph 104(1)(a) of these Regulations.

8 If the registered creator, or a person with whom they have entered into an agreement under section 21 of these Regulations, is the owner or operator of a hydrogen fuelling station, the following information with respect to the hydrogen supplied by those stations for use in Canada as a fuel for vehicles other than hydrogen fuel cell vehicles in accordance with paragraph 104(1)(b) of these Regulations:

(a) for each hydrogen fuelling station,
- (i) its name, GPS coordinates to the fifth decimal place and, if any, its civic address, and
- (ii) the quantity of hydrogen, expressed in kilograms, that is supplied to each class of hydrogen fuel cell vehicles listed in the Specifications for Fuel LCA Model CI Calculations;
(b) the carbon intensity of the hydrogen supplied to the vehicles referred to in subparagraph (a)(ii) that is the default carbon intensity referred to in paragraph 75(1)(a) of these Regulations or determined in accordance with paragraph 75(1)(b) or subsection 75(6) of these Regulations, that is approved under subsection 85(1) of these Regulations or that is the actual carbon intensity specified in the carbon-intensity-pathway report referred to in subsection 123(1) of these Regulations, as the case may be, and any alphanumeric identifier assigned to the carbon intensity;
(c) if feedstock is used to produce the hydrogen, the type of that feedstock and the region where it was extracted, harvested or produced;
(d) if eligible feedstock is used to produce the hydrogen, the maximum quantity of hydrogen, determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres, that is produced using the eligible feedstock in order to create compliance credits under paragraph 104(1)(b) of these Regulations and that is supplied to vehicles at each fuelling station; and
(e) the number of provisional compliance credits created under paragraph 104(1)(b) of these Regulations.

9 The following information with respect to each liquid low-carbon-intensity fuel that is produced or imported into Canada in order to create compliance credits and that the registered creator has either exported or sold for export during the compliance period or that is acquired in accordance with a transfer request referred to in section 108 of these Regulations and, during the compliance period, a person, other than a primary supplier or a registered creator, has exported or sold it for export:

(a) its quantity, expressed in cubic metres;
(b) its carbon intensity and any alphanumeric identifier assigned to it; and
(c) the number of compliance credits to be canceled and the account of the registered creator opened under section 28 of these Regulations into which the credits have been deposited.

10 The following information with respect to each gaseous low-carbon-intensity fuel that is produced or imported into Canada in order to create compliance credits and that the registered creator has either exported or sold for export during the compliance period or that is acquired in accordance with a transfer request referred to in section 108 of these Regulations and, during the compliance period, a person, other than a primary supplier or a registered creator, has exported or sold it for export:

(a) its quantity, expressed in cubic metres or kilograms;
(b) its carbon intensity and any alphanumeric identifier assigned to it; and
(c) the number of compliance credits to be canceled and the account of the registered creator opened under section 28 of these Regulations into which the credits have been deposited.

11 The following information with respect to any fuel or energy source for which compliance credits are created by the registered creator in accordance with section 88 of these Regulations:

(a) its carbon intensity and any alphanumeric identifier assigned to it under subsection 85(2) of these Regulations;
(b) in the case where its carbon intensity has been the subject of an application for temporary approval under subsection 91(1) of these Regulations,
- (i) the carbon intensity that has been temporarily approved under subsection 91(4) of these Regulations and any alphanumeric identifier assigned to it under subsection 91(5) of these Regulations,
- (ii) the period during which the temporarily approved carbon intensity was used to create compliance credits,
- (iii) the quantity of fuel supplied during the period referred to in subparagraph (ii),
- (iv) the energy density of the fuel or energy source, and
- (v) the number of compliance credits created during the period referred to in subparagraph (ii) in respect of which a credit adjustment has been requested;
(c) in the case where its carbon intensity that was used to create compliance credits is the carbon intensity referred to in paragraph 75(1)(a) or (b) of these Regulations,
- (i) its carbon intensity,
- (ii) the period during which the carbon intensity was used to create compliance credits,
- (iii) the quantity supplied during the period referred to in subparagraph (ii),
- (iv) the energy density of the fuel or energy source, and
- (v) the number of compliance credits created during the period referred to in subparagraph (ii) in respect of which a credit adjustment has been requested; and
(d) the total number of compliance credits referred to in subparagraphs (b)(v) and (c)(v) in respect of which a credit adjustment has been requested.

12 The following information with respect to any fuel or energy source for which compliance credits are created by the registered creator after June 30, 2024:

(a) if its carbon intensity is approved after June 30, 2024, that carbon intensity and any alphanumeric identifier assigned to it under subsection 85(2) of these Regulations;
(b) if its carbon intensity is approved on or before June 30, 2024, that carbon intensity and any alphanumeric identifier assigned to it under subsection 85(2) of these Regulations, as well as
- (i) the period during which the carbon intensity was used to create compliance credits,
- (ii) the quantity supplied during the period referred to in subparagraph (i), and
- (iii) the energy density of the fuel or energy source;
(c) in the case where its carbon intensity was used to create compliance credits before June 30, 2024 and that carbon intensity has been temporarily approved under subsection 91(4) of these Regulations or has been determined in accordance with section 75 of these Regulations, that carbon intensity and any alphanumeric identifier assigned to it, as well as
- (i) the period during which the carbon intensity was used to create compliance credits,
- (ii) the quantity supplied during the period referred to in subparagraph (i), and
- (iii) the energy density of the fuel; and
(d) the total number of compliance credits in respect of which a credit adjustment has been requested.

13 The total number of compliance credits referred to in sections 8 to 12 in respect of which a credit adjustment has been requested that are in any account of the registered creator opened under section 28 of these Regulations.

SCHEDULE 12

(Subsections 121(2) and (3), paragraph 158(5)(b) and Schedule 13)

Contents of Quarterly Credit-Creation Report

1 The following information with respect to the registered creator:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 The following information with respect to each liquid low-carbon-intensity fuel referred to in section 94 of these Regulations that is produced in Canada by the registered creator or the person with whom the registered creator has entered into an agreement under section 21 of these Regulations during the period to which the report relates:

(a) its type;
(b) the name, GPS coordinates to the fifth decimal place and, if any, the civic address of each facility at which the fuel is produced;
(c) its carbon intensity that is the default carbon intensity referred to in paragraph 75(1)(a) of these Regulations or that is approved under subsection 85(1) of these Regulations, as the case may be, and any alphanumeric identifier assigned to the carbon intensity under subsection 85(2) of these Regulations;
(d) the type of feedstock that was used to produce the fuel;
(e) the region where the feedstock was extracted, harvested or produced;
(f) its energy density, expressed in megajoules per cubic metre, as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations, at the election of the registered creator;
(g) its quantity determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres, that is produced using an eligible feedstock in order to create compliance credits in accordance with section 94 of these Regulations, and that is used in Canada;
(h) an indication of whether the fuel is a gasoline replacement or a diesel replacement; and
(i) the number of provisional compliance credits created under subsection 94(2) of these Regulations by the production of the fuel.

3 The following information with respect to each gaseous low-carbon-intensity fuel referred to in section 95 or 100 of these Regulations that is produced in Canada by the registered creator, or the person with whom the registered creator has entered into an agreement under section 21 of these Regulations, during of the period to which the report relates:

(a) its type;
(b) the name, GPS coordinates to the fifth decimal place and, if any, the civic address of each facility at which the fuel is produced;
(c) its carbon intensity that is the default carbon intensity referred to in paragraph 75(1)(a) of these Regulations or that is approved under subsection 85(1) of these Regulations, as the case may be, and any alphanumeric identifier assigned to the carbon intensity under subsection 85(2) of these Regulations;
(d) the type of feedstock that was used to produce the fuel;
(e) the region where the feedstock was extracted, harvested or produced;
(f) its energy density, as set out in column 2 of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator;
(g) in the case where the fuel is biogas, renewable natural gas, renewable propane or hydrogen in respect of which compliance credits are created in respect of the gaseous class,
- (i) its quantity determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres, that is produced using an eligible feedstock in order to create compliance credits in accordance with section 95 of these Regulations, and that is used in Canada, and
- (ii) the number of provisional compliance credits created under subsection 95(1) of these Regulations by the production of the fuel;
(h) in the case where the fuel is renewable natural gas or renewable propane in respect of which compliance credits are created in respect of the liquid class,
- (i) the name of the owner or operator of each fuelling station to which the fuel has been supplied,
- (ii) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each fuelling station to which the fuel has been supplied,
- (iii) its quantity determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres, that is produced using an eligible feedstock in order to create compliance credits in accordance with section 100 of these Regulations, and that is supplied to vehicles at each fuelling station, and
- (iv) the number of provisional compliance credits created under subsection 100(1) of these Regulations by the production of the fuel; and
(i) in the case where the fuel is biogas that is used in an equipment that produces electricity, the amount determined under subsection 95(3) of these Regulations and the value of
- (i) the total quantity of electricity that is produced by the equipment, expressed in megajoules,
- (ii) the heat energy that is produced by the equipment and used or sold, expressed in megajoules,
- (iii) the quantity of that biogas that is used in the equipment, expressed in cubic metres, and
- (iv) the energy density of the biogas as set out in item 1, column 2, of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator.

4 The following information for each liquid low-carbon-intensity fuel referred to in section 94 of these Regulations that is imported into Canada by the registered creator during the period to which the report relates:

(a) its type;
(b) the province into which the fuel is imported;
(c) the name of each foreign supplier who supplied a quantity of the fuel, as well as the GPS coordinates to the fifth decimal place and, if any, the civic address of each facility at which the fuel was produced;
(d) its carbon intensity that is the default carbon intensity referred to in paragraph 75(1)(a) of these Regulations or that is approved under subsection 85(1) of these Regulations, as the case may be, and any alphanumeric identifier assigned to the carbon intensity under subsection 85(2) of these Regulations;
(e) the type of feedstock that was used to produce the fuel;
(f) the region where the feedstock was extracted, harvested or produced;
(g) its energy density, expressed in megajoules per cubic metre, as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations, at the election of the registered creator;
(h) its quantity determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres, that is produced using an eligible feedstock and that is imported in order to create compliance credits in accordance with section 94 of these Regulations;
(i) an indication of whether the fuel is a gasoline replacement or a diesel replacement; and
(j) the number of provisional compliance credits created under subsection 94(2) of these Regulations by the import of the fuel.

5 The following information for each gaseous low-carbon-intensity fuel referred to in section 95 or 100 of these Regulations that is imported into Canada by the registered creator during the period to which the report relates:

(a) its type;
(b) the name of each foreign supplier who supplied a quantity of the fuel, as well as the GPS coordinates to the fifth decimal place and, if any, the civic address of each facility at which the fuel was produced;
(c) its carbon intensity that is the default carbon intensity referred to in paragraph 75(1)(a) of these Regulations or that is approved under subsection 85(1) of these Regulations and any alphanumeric identifier assigned to the carbon intensity under subsection 85(2) of these Regulations;
(d) the type of feedstock that was used to produce the fuel;
(e) the region where the feedstock was extracted, harvested or produced;
(f) its energy density, as set out in column 2 of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator;
(g) in the case where the fuel is biogas, renewable natural gas, renewable propane or hydrogen in respect of which compliance are created in respect of the gaseous class,
- (i) the province into which the fuel is imported,
- (ii) its quantity determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres, that is produced using an eligible feedstock and that is imported in order to create compliance credits in accordance with section 95 of these Regulations, and
- (iii) the number of provisional compliance credits created under subsection 95(4) of these Regulations by the import of the fuel;
(h) in the case where the fuel is renewable natural gas or renewable propane in respect of which compliance credits are created in respect of the liquid class,
- (i) the name of the owner or operator of each fuelling station to which the fuel has been supplied,
- (ii) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each fuelling station to which the fuel has been supplied,
- (iii) its quantity determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres, that is produced using an eligible feedstock that is imported in order to create compliance credits in accordance with section 100 of these Regulations, and that is supplied to vehicles at each fuelling station, and
- (iv) the number of provisional compliance credits that are created under subsection 100(2) of these Regulations by the import of the fuel; and
(i) in the case where the fuel is biogas that is used in an equipment that produces electricity, the amount determined under subsection 95(3) of these Regulations and the value of
- (i) the total quantity of electricity produced by the equipment, expressed in megajoules,
- (ii) the heat energy produced by the equipment and used or sold, expressed in megajoules,
- (iii) the quantity of that biogas used in the equipment, expressed in cubic metres, and
- (iv) the energy density of the biogas as set out in item 1, column 2, of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator.

6 If compliance credits that are created for a low-carbon-intensity fuel referred to in any of sections 2 to 5 are transferred by the registered creator to another participant in accordance with subsection 108(1) of these Regulations, the following information:

(a) the name of each participant to whom compliance credits are transferred;
(b) the quantity of low-carbon-intensity fuel that is sold to each participant, expressed in cubic metres;
(c) for each fuel that is sold to each participant, the carbon intensity that is the default carbon intensity referred to in paragraph 75(1)(a) of these Regulations or that is approved under subsection 85(1) of these Regulations and any alphanumeric identifier assigned to the carbon intensity under subsection 85(2) of these Regulations; and
(d) the number of compliance credits that are transferred to each participant for each fuel.

7 The following information for each quantity of electricity produced using biogas in respect of which provisional compliance credits have been created in accordance with subsection 96(3) of these Regulations during the period to which the report relates:

(a) the name, GPS coordinates to the fifth decimal place and, if any, the civic address of each facility at which the biogas is produced;
(b) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each facility at which electricity is produced;
(c) the carbon intensity of the biogas that is the default carbon intensity referred to in paragraph 75(1)(a) of these Regulations or that is approved under subsection 85(1) of these Regulations and any alphanumeric identifier assigned to the carbon intensity under subsection 85(2) of these Regulations;
(d) the type of feedstock that was used to produce the fuel;
(e) the region where the feedstock was extracted, harvested or produced;
(f) the energy density of the biogas, expressed in megajoules per cubic metre, as set out in item 1, column 2, of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator;
(g) the quantity of the biogas, expressed in cubic metres, produced using an eligible feedstock and determined in accordance with subsection 45(1) of these Regulations that is used in Canada in equipment for the production of electricity;
(h) the carbon intensity of the electricity that is produced using the biogas and determined in accordance with subsection 96(2) of these Regulations;
(i) the total quantity of electricity that is produced by the equipment using the biogas at each facility and used in the determination of the carbon intensity of the electricity;
(j) the quantity of electricity that is produced using the biogas at each facility and used to create provisional compliance credits; and
(i) the number of provisional compliance credits that are created under subsection 96(3) of these Regulations by the production of electricity.

SCHEDULE 13

(Subsection 122(2) and paragraphs 157(b) and 158(5)(b))

Contents of Credit-Adjustment Report

1 The following information with respect to the registered creator:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 For each three-month period during the compliance period, the following information with respect to each liquid low-carbon-intensity fuel with a particular carbon intensity whose production in Canada during that compliance period results in compliance credits being deposited into the account of their registered creator:

(a) its type;
(b) the name, GPS coordinates to the fifth decimal place and, if any, the civic address of each facility at which the fuel is produced;
(c) the carbon intensity of the fuel and any alphanumeric identifier assigned under subsection 85(2) of these Regulation, as set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(d) the carbon intensity of the fuel as set out in any carbon-intensity-pathway report submitted under subsection 123(1) of these Regulations for the same compliance period;
(e) the type of feedstock that was used to produce the fuel;
(f) the region where the feedstock was extracted, harvested or produced;
(g) the energy density of the fuel, expressed in megajoules per cubic metre, as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations, at the election of the registered creator;
(h) an indication of whether the fuel is a gasoline replacement or a diesel replacement;
(i) the quantity of the fuel, expressed in cubic metres, determined in accordance with subsection 45(1) of these Regulations, that is produced using an eligible feedstock in order to create compliance credits during the same three-month period and that is used in Canada;
(j) the difference between the quantity referred to in paragraph (i) and the quantity set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(k) the quantity of low-carbon-intensity fuel that was exported or sold for export during the period to which the report submitted under subsection 121(1) of these Regulations relates;
(l) the total number of compliance credits to be deposited into any account of the registered creator opened under section 28 of these Regulations and a description of the change or error, if any, which requires the adjustment of credits;
(m) the total number of compliance credits to be canceled from any account of the registered creator opened under section 28 of these Regulations, and a description of the change or error, if any, which requires the cancellation of credits; and
(n) the number of compliance credits, if any, that have been transferred to each participant under subsection 108(1) of these Regulations.

3 For each three-month period during the compliance period, the following information with respect to each gaseous low-carbon-intensity fuel with a particular carbon intensity referred to in section 95 or 100 of these Regulations whose production in Canada during that compliance period results in compliance credits being deposited into the account of the registered creator:

(a) its type;
(b) the name, GPS coordinates to the fifth decimal place and, if any, the civic address of each facility at which the fuel is produced;
(c) the type of feedstock that was used to produce the fuel;
(d) the region where the feedstock was extracted, harvested or produced;
(e) the energy density of the fuel, expressed in megajoules per cubic metre or per kilogram, as set out in column 2 of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator;
(f) in the case where the fuel is biogas, renewable natural gas, renewable propane or hydrogen in respect of which compliance credits are created in respect of the gaseous class,
- (i) the carbon intensity of the fuel and any alphanumeric identifier assigned under subsection 85(2) of these Regulation, as set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period,
- (ii) the carbon intensity set out in any report submitted under subsection 123(1) of these Regulations for the same compliance period,
- (iii) the quantity of the fuel, expressed in cubic metres or kilograms, as applicable, determined in accordance with subsection 45(1) of these Regulations that is produced using an eligible feedstock in order to create compliance credits under subsection 95(1) of these Regulations during the same three-month period and that is used in Canada, and
- (iv) the difference between the quantity referred to in subparagraph (iii) and the quantity set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(g) in the case where the fuel is renewable natural gas or renewable propane in respect of which compliance credits are created in respect of the liquid class,
- (i) the name of the owner or operator of each fuelling station to which the fuel has been supplied,
- (ii) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each fuelling station to which the fuel has been supplied,
- (iii) the carbon intensity of the fuel and any alphanumeric identifier assigned under subsection 85(2) of these Regulation, as set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period,
- (iv) the carbon-intensity of the fuel as set out in any report submitted under subsection 123(1) of these Regulations for the same compliance period,
- (v) the quantity of the fuel determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres, that is produced using an eligible feedstock in order to create compliance credits during the same three-month period in accordance with section 100 of these Regulations, and that is supplied to vehicles at each fuelling station, and
- (vi) the difference between the quantity referred to in subparagraph (v) and the quantity set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(h) the quantity of low-carbon-intensity fuel that was exported or sold for export during the period to which the report submitted under subsection 121(1) of these Regulations relates;
(i) in the case where the production of the low-carbon-intensity fuel results in the creation of compliance credits under subsection 95(1) of these Regulations,
- (i) the total number of compliance credits to be deposited into any account of the registered creator opened under paragraph 28(b) of these Regulations and a description of the change or error, if any, which requires the adjustment of credits, and
- (ii) the total number of compliance credits to be canceled from any account of the registered creator opened under paragraph 28(b) of these Regulations, and a description of the change or error, if any, which requires the cancellation of credits;
(j) in the case where the production of the low-carbon-intensity fuel results in the creation of compliance credits under subsection 100(1) of these Regulations,
- (i) the total number of compliance credits to be deposited into any account of the registered creator opened under paragraph 28(a) of these Regulations and a description of the change or error, if any, which requires the adjustment of credits, and
- (ii) the total number of compliance credits to be canceled from any account of the registered creator opened under paragraph 28(a) of these Regulations, and a description of the change or error, if any, which requires the cancellation of credits; and
(k) the number of compliance credits, if any, that are transferred to each participant under subsection 108(1) of these Regulations and the name of that participant.

4 For each three-month period during the compliance period, the following information with respect to each liquid low-carbon-intensity fuel with a particular carbon intensity whose import into Canada during that compliance period results in compliance credits being deposited into the account of their registered creator:

(a) its type;
(b) the province into which the fuel is imported;
(c) the name of each foreign supplier who supplied a quantity of the fuel, as well as the GPS coordinates to the fifth decimal place and, if any, the civic address of each facility at which the fuel was produced;
(d) the carbon intensity of the fuel and any alphanumeric identifier assigned under subsection 85(2) of these Regulations, as set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(e) the carbon intensity of the fuel as set out in any report submitted under subsection 123(1) of these Regulations for the same compliance period;
(f) the type of feedstock that was used to produce the fuel;
(g) the region where the feedstock was extracted, harvested or produced;
(h) the energy density of the fuel, expressed in megajoules per cubic metre, as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations, at the election of the registered creator;
(i) the quantity of the fuel, expressed in cubic metres, determined in accordance with subsection 45(1) of these Regulations, that is produced using an eligible feedstock and that is imported in order to create compliance credits during the same three-month period and that is used in Canada;
(j) the difference between the quantity referred to in paragraph (i) and the quantity set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(k) the quantity of low-carbon-intensity fuel that was exported or sold for export during the period to which the report submitted under subsection 121(1) of these Regulations relates;
(l) the total number of compliance credits to be deposited into any account of the registered creator opened under section 28 of these Regulations and a description of the change or error, if any, which requires the adjustment of credits;
(m) the total number of compliance credits to be canceled from any account of the registered creator opened under section 28 of these Regulations, and a description of the change or error, if any, which requires the cancellation of credits; and
(n) the number of compliance credits, if any, that have been transferred to each participant under subsection 108(1) of these Regulations.

5 For each three-month period during the compliance period, the following information with respect to each gaseous low-carbon-intensity fuel with a particular carbon intensity referred to in section 95 or 100 of these Regulations whose import into Canada during that compliance period results in compliance credits being deposited into the account of their registered creator:

(a) its type;
(b) the province into which the fuel is imported;
(c) the name of each foreign supplier who supplied a quantity of the fuel, as well as the GPS coordinates to the fifth decimal place and, if any, the civic address of each facility at which the fuel was produced;
(d) the type of feedstock that was used to produce the fuel;
(e) the region where the feedstock was extracted, harvested or produced;
(f) its carbon intensity set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period and any report submitted under subsection 123(1) of these Regulations for the same compliance period, and any alphanumeric identifier assigned under subsection 85(2) of these Regulations;
(g) the energy density of the fuel, expressed in megajoules per cubic metre or per kilogram, as set out in column 2 of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator;
(h) in the case where the fuel is biogas, renewable natural gas, renewable propane or hydrogen in respect of which compliance credits are created in respect of the gaseous class,
- (i) the carbon intensity of the fuel and any alphanumeric identifier assigned under subsection 85(2) of these Regulation, as set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period,
- (ii) the carbon intensity set out in any report submitted under subsection 123(1) of these Regulations for the same compliance period,
- (iii) the quantity of the fuel, expressed in cubic metres or kilograms, as applicable, determined in accordance with subsection 45(1) of these Regulations that is produced using an eligible feedstock in order to create compliance credits under subsection 95(1) of these Regulations during the same three-month period and that is used in Canada, and
- (iv) the difference between the quantity referred to in subparagraph (iii) and the quantity set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(i) in the case where the fuel is renewable natural gas or renewable propane in respect of which compliance credits are created in respect of the liquid class,
- (i) the name of the owner or operator of each fuelling station to which the fuel has been supplied,
- (ii) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each fuelling station to which the fuel has been supplied,
- (iii) the carbon intensity of the fuel and any alphanumeric identifier assigned under subsection 85(2) of these Regulation, as set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period,
- (iv) the carbon-intensity of the fuel as set out in any report submitted under subsection 123(1) of these Regulations for the same compliance period,
- (v) the quantity of the fuel determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres, that is produced using an eligible feedstock that is imported in order to create compliance credits during the same three-month period in accordance with section 100 of these Regulations, and
- (vi) the difference between the quantity referred to in subparagraph (v) and the quantity set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(j) the quantity of low-carbon-intensity fuel that was exported or sold for export during the period to which the report submitted under subsection 121(1) of these Regulations relates;
(k) in the case where the import of the low-carbon-intensity fuel results in the creation of compliance credits under subsection 95(1) of these Regulations,
- (i) the total number of compliance credits to be deposited into any account of the registered creator opened under paragraph 28(b) of these Regulations and a description of the change or error, if any, which requires the adjustment of credits, and
- (ii) the total number of compliance credits to be canceled from any account of the registered creator opened under paragraph 28(b) of these Regulations, and a description of the change or error, if any, which requires the cancellation of credits;
(l) in the case where the import of the low-carbon-intensity fuel results in the creation of compliance credits under subsection 100(1) of these Regulations,
- (i) the total number of compliance credits to be deposited into any account of the registered creator opened under paragraph 28(a) of these Regulations and a description of the change or error, if any, which requires the adjustment of credits, and
- (ii) the total number of compliance credits to be canceled from any account of the registered creator opened under paragraph 28(a) of these Regulations, and a description of the change or error, if any, which requires the cancellation of credits; and
(m) the number of compliance credits, if any, that have been transferred to each participant under subsection 108(1) of these Regulations.

6 The following information with respect to each low-carbon-intensity fuel, other than those referred to in sections 2 to 5, for which compliance credits have been created:

(a) the quantity of the fuel that was exported or sold for export during the period to which the report relates;
(b) its carbon intensity and any alphanumeric identifier assigned to it under subsection 85(2) of these Regulations; and
(c) the total number of compliance credits to be canceled from any account of the registered creator opened under section 28 of these Regulations.

7 For each three-month period during the compliance period, the following information for each quantity of electricity produced using biogas with a particular carbon intensity whose production in Canada during that compliance period resulted in the deposit of provisional compliance credits into the account of the registered creator:

(a) the name, GPS coordinates to the fifth decimal place and, if any, the civic address of each facility at which the biogas is produced;
(b) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each facility at which electricity is produced;
(c) the carbon intensity of the biogas and any alphanumeric identifier assigned to the biogas under subsection 85(2) of these Regulations, as set out in the report submitted under subsection 121(1) of these Regulations;
(d) the carbon intensity of the biogas as set out in any report submitted under subsection 123(1) of these Regulations for the same compliance period;
(e) the type of feedstock that was used to produce the fuel;
(f) the region where the feedstock was extracted, harvested or produced;
(g) the carbon intensity of the electricity that is produced using the biogas as set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(h) the carbon intensity of the electricity that is produced using the biogas, as determined in accordance with subsection 96(2) of these Regulations;
(i) the energy density of the biogas, expressed in megajoules per cubic metre or per kilogram, as set out in item 1, column 2, of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator;
(j) the quantity of the biogas, expressed in cubic metres, determined in accordance with subsection 45(1) of these Regulations that is produced using an eligible feedstock and that is used in equipment for the production of electricity in Canada in order to create compliance credits during the same three-month period;
(k) the difference between the quantity referred to in subparagraph (j) and the quantity set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(l) the total quantity of electricity that is produced by the equipment using the biogas at each facility during the same three-month period and that is used in the determination of the carbon intensity of the electricity;
(m) the difference between the total referred to in paragraph (l) and the total set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(n) the quantity of electricity that is produced using the biogas and used to create compliance credits during the same three-month period; and
(o) the difference between the quantity referred to in paragraph (n) and the quantity set out in the report submitted under subsection 121(1) of these Regulations for the same three-month period;
(p) for the biogas used in the production of the electricity, the total number of compliance credits to be deposited into any account of the registered creator opened under section 28 of these Regulations and a description of the change or error, if any, which requires the adjustment of credits; and
(q) for the biogas used in the production of the electricity, the total number of compliance credits to be canceled from any account of the registered creator opened under section 28 of these Regulations, and a description of the change or error, if any, which requires the cancellation of credits.

8 The following information with respect to each low-carbon-intensity fuel for which the registered creator has requested the creation of compliance credits under sections 88 and 89 of these Regulations:

(a) the carbon intensity of the fuel and the alphanumeric identifier assigned to it under subsection 85(2) of these Regulations;
(b) in the case where its carbon intensity has been the subject of an application for temporary approval under subsection 91(1) of these Regulations,
- (i) any carbon intensity that has been temporarily approved under subsection 91(4) of these Regulations and any alphanumeric identifier assigned to it under subsection 91(5) of these Regulations,
- (ii) the period during which the temporarily approved carbon intensity was used to create compliance credits,
- (iii) the quantity of fuel that is determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres or kilograms, that is produced using an eligible feedstock and supplied during the period referred to in subparagraph (ii),
- (iv) the energy density of the fuel, expressed in megajoules per cubic metre or per kilogram, as set out in column 2 of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator,
- (v) the number of compliance credits to be deposited into any account of the registered creator opened under section 28 of these Regulations, for the period referred to in subparagraph (ii), and
- (vi) the number of compliance credits to be canceled from any account of the registered creator opened under section 28 of these Regulations for the period referred to in subparagraph (ii);
(c) in the case where its carbon intensity that was used to create compliance credits is the carbon intensity referred to in paragraph 75(1)(a) of these Regulations,
- (i) its carbon intensity,
- (ii) the period during which the carbon intensity was used to create compliance credits,
- (iii) the quantity of fuel that is determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres or kilograms, that is produced using an eligible feedstock and supplied during the period referred to in subparagraph (ii),
- (iv) its energy density, expressed in megajoules per cubic metre or per kilogram, as set out in column 2 of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator,
- (v) the number of compliance credits to be deposited into any account of the registered creator opened under section 28 of these Regulations, for the period referred to in subparagraph (ii), and
- (vi) the number of compliance credits to be canceled from any account of the registered creator opened under section 28 of these Regulations for the period referred to in subparagraph (ii);
(d) in the case where its carbon intensity is determined in accordance with paragraph 75(1)(b) of these Regulations,
- (i) its carbon intensity and any alphanumeric identifier assigned to it under subsection 85(2) of these Regulations,
- (ii) the period during which the carbon intensity was used to create compliance credits,
- (iii) the quantity of fuel that is determined in accordance with subsection 45(1) of these Regulations, expressed in cubic metres or kilograms, that is produced using an eligible feedstock and supplied during the period referred to in subparagraph (ii),
- (iv) its energy density, expressed in megajoules per cubic metre or per kilogram, as set out in column 2 of Schedule 2, as set out in the Specifications for Fuel LCA Model CI Calculations or as measured in accordance with section 162 of these Regulations, at the election of the registered creator,
- (v) the number of compliance credits to be deposited into any account of the registered creator opened under paragraph 28(a) of these Regulations, for the period referred to in subparagraph (ii), and
- (vi) the number of compliance credits to be canceled from any account of the registered creator opened under paragraph 28(a) of these Regulations for the period referred to in subparagraph (ii).

9 The following information with respect to each low-carbon-intensity fuel for which the registered creator has requested the creation of compliance credits after July 1, 2024:

(a) the carbon intensity of the fuel that is approved after July 1, 2024 and the alphanumeric identifier assigned to it under subsection 85(2) of these Regulations;
(b) the carbon intensity that is set out in any report submitted under subsection 123(1) of these Regulations for the same compliance period;
(c) in the case where the carbon intensity of the fuel has been approved before June 30, 2024, that carbon intensity and the alphanumeric identifier assigned to it under subsection 85(2) of these Regulations, as well as
- (i) the period during which the approved carbon intensity was used to create compliance credits,
- (ii) the quantity of fuel, expressed in cubic metres or kilograms, determined in accordance with subsection 45(1) of these Regulations that is produced using an eligible feedstock that was supplied during the period referred to in subparagraph (i), and
- (iii) the energy density of the fuel, expressed in megajoules per cubic metre or per kilogram, as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations, at the election of the registered creator;
(d) in the case where the carbon intensity has been temporarily approved under subsection 91(4) of these Regulations or has been determined in accordance with paragraph 75(1)(b) of these Regulations and used to create compliance credits before June 30, 2024, that carbon intensity and any alphanumeric identifier assigned to it under subsection 85(2) of these Regulations, as well as
- (i) the period during which the carbon intensity was used to create compliance credits,
- (ii) the quantity of fuel expressed in cubic metres or kilograms, determined in accordance with subsection 45(1) of these Regulations that is produced using an eligible feedstock that was supplied during the period referred to in subparagraph (i), and
- (iii) the energy density of the fuel, expressed in megajoules per cubic metre or per kilogram, as set out in column 2 of Schedule 2 or as set out in the Specifications for Fuel LCA Model CI Calculations, at the election of the registered creator; and
(e) the total number of compliance credits to be deposited into any account of the registered creator opened under section 28 of these Regulations.

10 The following information with respect to any modification or error, other than any that are referred to in sections 2 to 9:

(a) the nature of the modification or error;
(b) the provision of Schedule 12 to which it relates;
(c) the number of compliance credits to be deposited into any account of the registered creator opened under section 28 of these Regulations; and
(d) the number of compliance credits to be canceled from any account of the registered creator opened under section 28 of these Regulations.

11 The total number of compliance credits that are referred to in sections 2 to 9 and that are in any account of the registered creator opened under section 28 of these Regulations that should be canceled.

12 The total number of compliance credits that are referred to in sections 2 to 9 that should be created and deposited in an account of the registered creator opened under section 28 of these Regulations.

13 The net total number of compliance credits that are in any account of the registered creator opened under section 28 of these Regulations in respect of which a credit adjustment has been requested.

SCHEDULE 14

(Paragraph 1(4)(p) and subsection 123(2))

Contents of Carbon-Intensity-Pathway Report

1 The following information with respect to the registered creator, carbon-intensity contributor or foreign supplier:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 In the case of a fuel or material input with an approved carbon intensity determined in accordance with paragraph 75(1)(b) or section 76 or 77 of these Regulations, the following information:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of the production facility where the low-carbon-intensity fuel or material input was produced;
(b) the type of low-carbon-intensity fuel or material input for which the determination was made;
(c) if the approved carbon intensity was determined in accordance with paragraph 75(1)(b) of these Regulations,
- (i) the type of feedstock that was used to produce the fuel or material input,
- (ii) if a feedstock was extracted, harvested or produced, the region where it was extracted , harvested or produced, as the case may be,
- (iii) the carbon intensity of the fuel or material input that was approved under subsection 85(1) of these Regulations and any alphanumeric identifier that was assigned to that carbon intensity,
- (iv) the type of thermal energy and the source of electricity used at the production facility,
- (v) if the application for the approval of the carbon intensity indicated that the variable CI_p of the formula that is referred to in paragraph 75(1)(b) of these Regulations has a value of 13 g/MJ, the percentage of the electrical and thermal energy used at the production facility that is from non-fossil sources, electricity with a carbon intensity of less than 100 g/MJ, hydrogen from renewable sources, hydrogen from natural gas with carbon capture and storage or a mix of those sources and the estimated quantity of thermal energy and electricity from each source, and
- (vi) if the application for the approval of the carbon intensity indicated that the variable CI_td of the formula that is referred to in paragraph 75(1)(b) of these Regulations has a value of 0 g/MJ, the distance between the site where the feedstock was extracted, harvested or produced and the production facility where the fuel or material input was produced and the distance between that facility and the final location where the fuel or material input is distributed to end users; and
(d) if the approved carbon intensity was determined in accordance with section 76 or 77 of these Regulations,
- (i) a copy of the pathway from the Fuel LCA Model, including all data that are input into the Fuel LCA Model and all results that are obtained from it using input data for the compliance period and the preceding compliance period,
- (ii) the carbon intensity of the fuel or material input, rounded to the nearest hundredth of a gram of CO₂e per megajoule,
- (iii) if an additional value referred to in subsection 80(2) of these Regulations has been added to the carbon intensity referred to in subparagraph (ii), the additional value and the sum of the additional value and the carbon intensity value, rounded to the nearest hundredth of a gram of CO₂e per megajoule,
- (iv) if the pathway from the Fuel LCA Model that was used for the determination of the carbon intensity is a new pathway, any alphanumeric identifier assigned to the new pathway under subsection 81(4) of these Regulations,
- (v) a description of the data sources and the methods used to collect and determine the data that are entered into a data workbook,
- (vi) a copy of the data workbook, including any calculations performed on the data, that is consistent with the Specifications for Fuel LCA Model CI Calculations and used to determine the data that are inputted into the Fuel LCA Model,
- (vii) any supporting documentation required by the Specifications for Fuel LCA Model CI Calculations, and
- (viii) the information listed in any applicable emission-reduction quantification method established under subsection 31(1) or 32(1) of these Regulations.

3 In the case of a carbon intensity determined in accordance with section 78 of these Regulations, the following information:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each location where a fuelling station supplied the fuel;
(b) the GPS coordinates to the fifth decimal place and, if any, civic address of each location, other than a fuelling station, where propane, renewable propane, co-processed low-carbon-intensity propane, natural gas, renewable natural gas or hydrogen is liquefied or compressed for use in the fuelling station;
(c) the type of fossil fuel supplied, if any, to each fuelling station referred to in paragraph (a);
(d) the type of low-carbon-intensity fuel supplied, if any, to vehicles at each fuelling station referred to in paragraph (a);
(e) a copy of the pathway from the Fuel LCA Model, including all data that are inputted into the Fuel LCA Model and all results that are obtained from it, using input data for the compliance period and the preceding compliance period;
(f) the carbon intensity of the fuel determined in accordance with the Fuel LCA Model, rounded to the nearest hundredth of a gram of CO₂e per megajoule;
(g) if an additional value referred to in subsection 80(2) of these Regulations has been added to the carbon intensity referred to in paragraph (f), the additional value and the sum of the additional value and the carbon intensity value, rounded to the nearest hundredth of a gram of CO₂e per megajoule;
(h) in the case of a new pathway, any alphanumeric identifier assigned to the new pathway under subsection 81(4) of these Regulations;
(i) a description of the data sources and the methods used to collect and determine the data that are entered into a data workbook;
(j) a copy of the data workbook, including any calculations performed on the data, that is consistent with the Specifications for Fuel LCA Model CI Calculations and used to determine the data that are inputted into the Fuel LCA Model;
(k) any supporting documentation required by the Specifications for Fuel LCA Model CI Calculations; and
(l) the information listed in any applicable emission-reduction quantification method established under subsection 31(1) or 32(1) of these Regulations.

4 In the case of a carbon intensity determined in accordance with section 79 of these Regulations, the following information:

(a) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each facility or location where there is one or more charging stations or fuelling stations to which any electricity was supplied;
(b) the GPS coordinates to the fifth decimal place and, if any, civic address of each site where any electricity was produced, other than a facility or location referred to in paragraph (a);
(c) a copy of the pathway from the Fuel LCA Model, including all data that are inputted into the Fuel LCA Model and all results that are obtained from it, using input data for the compliance period and the preceding compliance period;
(d) the carbon intensity of the electricity determined in accordance with the Fuel LCA Model, rounded to the nearest hundredth of a gram of CO₂e per megajoule;
(e) if an additional value referred to in subsection 80(2) of these Regulations has been added to the carbon intensity value referred to in paragraph (d), the additional value and the sum of the additional value and the carbon intensity value, rounded to the nearest hundredth of a gram of CO₂e per megajoule;
(f) in the case of a new pathway, any alphanumeric identifier assigned to the new pathway under subsection 81(4) of these Regulations;
(g) a description of the data sources and the methods used to collect and determine the data that are entered into a data workbook;
(h) a copy of the data workbook, including any calculations performed on the data, that is consistent with the Specifications for Fuel LCA Model CI Calculations and used to determine the data that are inputted into the Fuel LCA Model;
(i) any supporting documentation required by the Specifications for Fuel LCA Model CI Calculations; and
(j) the information listed in any applicable emission-reduction quantification method established under subsection 31(1) or 32(1) of these Regulations.

5 If the determination of the carbon intensity includes a carbon intensity that was approved under subsection 85(1) of these Regulations and transferred from a carbon-intensity contributor, foreign supplier or registered creator, the following information:

(a) the name, civic address, postal address, telephone number and, if any, email address, of the carbon-intensity contributor, foreign supplier or registered creator;
(b) the type of low-carbon-intensity fuel, material input or energy source that they provided; and
(c) the approved carbon intensity of the low-carbon-intensity fuel, material input or energy source referred to in paragraph (b) and the alphanumeric identifier assigned to it under section 85(2) of these Regulations.

6 If the actual carbon intensity specified in the report is different than the carbon intensity that was approved under subsection 85(1) of these Regulations, information that explains the difference.

SCHEDULE 15

(Paragraph 1(4)(q) and subsection 124(2))

Contents of Material Balance Report

1 The following information with respect to the registered creator or foreign supplier:

(a) their name, civic address, postal address, telephone number and, if any, email address; and
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent.

2 An indication of whether the feedstock that was used to produce the low-carbon-intensity fuel is a feedstock referred to in paragraph 46(1)(b) or (c) of these Regulations.

3 The type of feedstock that was used to produce the low-carbon-intensity fuel for which compliance credits may be created by carrying out a CO₂e-emission-reduction project described in paragraph 30(d) of these Regulations or under any of sections 94 to 96, 99, 100 and 104 of these Regulations.

4 The type of low-carbon-intensity fuel that was produced.

5 The alphanumeric identifier assigned to the carbon intensity of the fuel under subsection 72(2) of these Regulations or the default carbon intensity that is referred to in paragraph 75(1)(a), whichever is applicable.

6 The energy density of the low-carbon-intensity fuel, expressed in megajoules per cubic metre.

7 The following information in respect of each period set out in subsection 45(3):

(a) the total quantity of low-carbon-intensity fuel referred to in subsection 45(1) of these Regulations;
(b) the quantity of the low-carbon-intensity fuel produced, which must be equal to or less than the quantity referred to in subsection 45(1) of these Regulations, using eligible feedstock for the purpose of creating compliance credits or to be imported into Canada for the purpose of creating compliance credits;
(c) the quantity of eligible feedstock used to produce the low-carbon-intensity fuel referred to in subsection 45(1) of these Regulations, expressed in kilograms or cubic metres, as applicable;
(d) the quantity of the feedstock, other than the quantity of an eligible feedstock, that was used to produce the low-carbon-intensity fuel referred to in subsection 45(1) of these Regulations, expressed in kilograms or cubic metres, as applicable;
(e) the quantity of eligible feedstock referred to in subsection 47(2) of these Regulations that was used to produce the low-carbon-intensity fuel in each of the facilities at the start of the period, expressed in kilograms or cubic metres, as applicable; and
(f) the quantity of eligible feedstock referred to in subsection 47(2) of these Regulations that was used to produce the low-carbon-intensity fuel and that was brought to the facility during the period , expressed in kilograms or in cubic metres, as applicable.

8 If the foreign supplier supplies low-carbon-intensity fuel to any person who imports that fuel into Canada, the following information:

(a) the name, civic address, postal address, telephone number and, if any, email address of the person who imported the low-carbon-intensity fuel;
(b) the unique identifier used by the foreign supplier for their internal accounting purposes for each declaration referred to in subsection 58(3) of these Regulations that was provided by the foreign supplier to the person who imports the fuel into Canada; and
(c) the total quantity of the low-carbon-intensity fuel, expressed in kilograms or cubic metres, that was produced using eligible feedstock and supplied to the person who imports the fuel into Canada for the purpose of creating compliance credits.

SCHEDULE 16

(Subsection 125(2))

Contents of Compliance-Credit Revenue Report

1 The following information with respect to the registered creator:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 The number of compliance credits that the registered creator transferred during the compliance period referred to in paragraph 125(1)(a) of these Regulations.

3 The total revenue from the transfer of the compliance credits referred to in section 2.

4 The amount that the registered creator spent during each compliance period referred to in paragraph 125(1)(b) of these Regulations in respect of the following activities:

(a) expanding electric vehicle charging infrastructure, including charging stations and electricity distribution infrastructure that supports electric vehicle charging, whether intended primarily for use by the occupants of a private dwelling-place or by the public; and
(b) reducing the cost of electric vehicle ownership through financial incentives to purchase or operate an electric vehicle.

5 A description of each of the activities referred to in section 4 that the registered creator carried out.

6 For each compliance period referred to in paragraph 125(1)(b) of these Regulations, the amount of revenue that is derived from the transferring of compliance credits during that compliance period that must be used in accordance with subsection 103(1) of these Regulations but has not yet been used.

7 The amount of revenue, if any, derived from the transferring of compliance credits during any compliance period preceding the compliance period referred to in section 6 that has not yet been used.

SCHEDULE 17

(Subsection 126(2))

Contents of Compliance-Credit Balance Report

1 The following information with respect to the registered creator or primary supplier:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 With respect to each of the specific types of compliance credits that are referred to in subsection 106(3), the following information:

(a) the number of those compliance credits that the registered creator created as provisional compliance credits during the compliance period;
(b) the number of those compliance credits that the registered creator or primary supplier transferred s in accordance with subsection 106(5) of these Regulations during the compliance period;
(c) the number of those compliance credits that were deposited in the registered creator’s or primary supplier’s accounts in accordance with subsection 106(5) of these Regulations during the compliance period;
(d) the number of those compliance credits that were transferred from the registered creator’s accounts in accordance with subsection 108(1) of these Regulations during the compliance period;
(e) the number of those compliance credits that were deposited in the registered creator’s or primary supplier’s accounts in accordance with subsection 108(1) of these Regulations during the compliance period;
(f) the number of those compliance credits that were transferred from the registered creator’s or primary supplier’s accounts in accordance with section 109 of these Regulations during the compliance period;
(g) the number of those compliance credits that were created as provisional compliance credits during the compliance period or any preceding compliance period and that were in the registered creator’s or primary supplier’s accounts on the July 31 that follows the end of the compliance period;
(h) the number of those compliance credits that the registered creator or primary supplier offers to transfer through the compliance-credit clearance mechanism in accordance with subsection 110(1) of these Regulations; and
(i) the number of those compliance credits that were transferred from the registered creator’s or primary supplier’s accounts during the compliance period preceding the current compliance period in accordance with subsection 112(1) of these Regulations.

SCHEDULE 18

(Subsection 127(2 and 158(5)(b)))

Contents of Compliance Report

1 The following information with respect to the primary supplier:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 The following information with respect to each type of liquid fuel that is described in paragraph 8(1)(a) or (b) of these Regulations:

(a) its type;
(b) in the case where the fuel is produced in Canada,
- (i) the name, GPS coordinates to the fifth decimal place and, if any, civic address of each facility at which the fuel was produced, and
- (ii) the quantity of fuel produced in each facility referred to in subparagraph (i), expressed in cubic metres, other than any fuel that is referred to in paragraphs 4(2)(a) to (d) of these Regulations;
(c) in the case where the fuel was imported into Canada,
- (i) the quantity of the fuel imported into each province, expressed in cubic metres, other than any fuel that is referred to in paragraphs 4(2)(a) to (d) of these Regulations, and its point of entry into that province,
- (ii) the method used to transport the fuel, and
- (iii) if the fuel is part of a blend, the components of that blend and the proportion of that blend that is a fossil fuel;
(d) in the case of gasoline, the volume that is referred to in subsection 6(2) of these Regulations;
(e) in the case of diesel, the volumes that are referred to in subsection 7(2) of these Regulations;
(f) for each of the primary supplier’s fuel production facilities referred to in subparagraph (b)(i), the quantity of each fuel referred to in paragraphs 8(2)(a) to (e) of these Regulations that is produced at that fuel production facility and that the primary supplier is subtracting from their pool, expressed in cubic metres;
(g) for each province, the quantity of each fuel referred to in paragraphs 8(2)(a) to (e) of these Regulations that is imported into Canada by the primary supplier and that the primary supplier is subtracting from their pool, expressed in cubic metres;
(h) the volume of each fuel that is subject to the volumetric requirements set out in subsections 6(1) and 7(1) of these Regulations;
(i) the volume of each fuel that is subject to the reduction requirement;
(j) the primary supplier’s reduction requirement with respect to the fuel; and
(k) the primary supplier’s total reduction requirement.

3 The quantity of each fuel referred to in paragraphs 4(2)(a) to (d) of these Regulations that the primary supplier produced in Canada or imported into Canada, expressed in cubic metres.

4 If the primary supplier made a contribution to a registered emission-reduction funding program in accordance with paragraph 118(1)(a) of these Regulations,

(a) the name of the registered emission-reduction funding program;
(b) the amount of the contribution;
(c) the number of compliance credits created by making the contribution; and
(d) the receipt referred to in subsection 118(2) of these Regulations.

5 The following information with respect to the compliance credits that the primary supplier will use to satisfy the reduction requirement and the volumetric requirements set out in subsections 6(1) and 7(1) of these Regulations in respect of their pool of gasoline or diesel in accordance with sections 11 and 12 of these Regulations:

(a) the number of compliance credits referred to in paragraph 4(c) that they will use to reduce the reduction requirement;
(b) the number of each of the specific types of compliance credits that are referred to in subsection 106(3) of these Regulations that they will use to reduce the reduction requirement and satisfy the volumetric requirements set out in subsections 6(1) and 7(1) of these Regulations;
(c) the number of each of the specific types of compliance credits referred to in subsection 106(3) of these Regulations that were created with respect to a gasoline replacement and, for each such compliance credit, the volume of the fuel that is associated with it as well as the carbon intensity and any alphanumeric identifier to it;
(d) the number of each of the specific types of compliance credits referred to in subsection 106(3) of these Regulations that were created with respect to a diesel replacement and, for each such compliance credit, the volume of the fuel that is associated with it as well as the carbon intensity and any alphanumeric identifier to it; and
(e) the total number of compliance credits from each of the primary supplier’s accounts that they will use to reduce the reduction requirement.

6 If the primary supplier has, in accordance with subsection 16(1) of these Regulations, deferred satisfaction of their reduction requirements in respect of a pool of gasoline or diesel for one of the five compliance periods that immediately precede the compliance period to which the report relates, the following information:

(a) the number of compliance credits that they must use in accordance with subsection 18(1) of these Regulations in order to satisfy the deferred portion of their reduction requirements in accordance with subsection 16(3) of these Regulations; and
(b) the number of each of the specific types of compliance credits that are referred to in subsection 106(3) of these Regulations that they must use in accordance with subsection 18(1) of these Regulations; and
(c) the number of compliance credits referred to in paragraph 4(c) that they must use in order to reduce the deferred portion of the reduction requirements.

7 Unless the information is otherwise provided by the primary supplier in a report they submit under section 120 or 122 of these Regulations, the quantity and carbon intensity of each liquid or gaseous low-carbon-intensity fuel that was produced in Canada or imported into Canada and was used to create compliance credits, if

(a) during the compliance period, the primary supplier exported the fuel or sold the fuel for export; or
(b) the primary supplier acquired the fuel in accordance with a transfer request referred to in section 108 of these Regulations and, during the compliance period, the fuel was exported or sold for export by a person who is not a primary supplier nor a registered creator.

8 With respect to each low-carbon-intensity fuel referred to in section 7, the number of compliance credits that should be cancelled and the specific accounts in which they are located.

SCHEDULE 19

(Subsection 128(2))

Contents of Complementary Compliance Report

1 The following information with respect to the primary supplier:

(a) their name, civic address, postal address, telephone number and, if any, email address;
(b) the name, title, civic address, postal address, telephone number and, if any, email address of their authorized agent; and
(c) the name, title, civic address, postal address, telephone number and, if any, email address of a contact person, unless the contact person is the authorized agent.

2 If the primary supplier has not satisfied the reduction requirement for a compliance period in respect of gasoline or diesel on the July 31 that follows the expiry of the compliance period, the following information:

(a) the value of the reduction requirement that has not been satisfied in respect of gasoline or diesel, expressed in tonnes of CO₂e; and
(b) the value of the volumetric requirement that is determined under, in the case of gasoline, subsection 6(1) of these Regulations or, in the case of diesel, subsection 7(1) of these Regulations and that has not been satisfied, expressed in cubic metres.

3 With respect to each of the specific types of compliance credits that are referred to in subsection 106(3) of these Regulations, the number of those compliance credits that were transferred to the primary supplier through the credit clearance mechanism in accordance with section 112 of these Regulations.

4 The number of compliance credits referred to in section 3 that were created with respect to a gasoline replacement or diesel replacement and, for each compliance credit, the volume of the fuel that is associated with it as well as the carbon intensity and any alphanumeric identifier to it.

5 If the primary supplier made a contribution to a registered emission-reduction funding program in accordance with paragraph 118(1)(b) of these Regulations,

(a) the name of the registered emission-reduction funding program;
(b) the amount of the contribution;
(c) the number of compliance credits created by making the contribution; and
(d) the receipt referred to in subsection 118(2) of these Regulations.

6 If the primary supplier will defer satisfaction of the reduction requirement with respect to gasoline or diesel, for the compliance period in accordance with subsection 16(1) of these Regulations, the value of the reduction requirement that has been deferred and the types of fuel to which the deferral applies.

7 If the primary supplier has, in accordance with subsection 16(1) of these Regulations, deferred satisfaction of their reduction requirements in respect of gasoline or diesel for one of the five compliance periods that immediately precede the compliance period to which the report relates, the following information:

(a) the number of compliance credits that they must use in accordance with subsection 18(1) of these Regulations in order to satisfy the deferred portion of the reduction requirements for each previous compliance period in accordance with subsection 16(3) of these Regulations;
(b) the number of each of the specific types of compliance credits that are referred to in subsection 106(3) of these Regulations that they must use in accordance with subsection 18(1) of these Regulations; and
(c) the number of compliance credits referred to in paragraph 5(c) that they must use in order to reduce the deferred portion of the reduction requirements.

SCHEDULE 20

(Section 133)

Contents of Verification Report

1 The verification statement, which consists of the following information:

(a) with respect to the application or report that is being verified,
- (i) the name of the application or report,
- (ii) the date on which the application is made and the date of the compliance period related to the report,
- (iii) a summary of the application or report,
- (iv) the name of the person who is making the application or submitting the report, as well as the name of any facility referred to in the application or report, and
- (v) the name of any individual who is responsible for the preparation or submission of the application or report;
(b) with respect to the activities conducted as part of a verification,
- (i) the verification body’s declarations of its responsibilities and the basis of its opinion,
- (ii) a description of the materiality thresholds used by the verification body,
- (iii) the verification body’s declaration that the verification team and the independent reviewer, as well as any verifiers to whom verification activities have been outsourced, are all independent of the person who is making the application or submitting the report and independent of any employees of the federal public administration who administer or implement these Regulations or carry out any related activities,
- (iv) the verification body’s declaration that it has performed the verification of the application or report in accordance with ISO Standard 14064-3:2019 and an indication of which requirements of these Regulations were verified using Canadian auditing standards or ISO Standard 14044, as the case may be,
- (v) a description of the activities conducted as part of the verification, including any sites where the site visits referred to in section 152 of these Regulations were carried out, the National Pollutant Release Inventory identification number, if any, assigned to the site for the purposes of section 48 of the Act, and, in the case of production facilities, the date of the most recent site visit to that facility,
- (vi) for each member of the verification team, their name, the position held by the member at the time of the verification activities and a statement specifying whether the member is an employee of the verification body or a person to whom any verification activities have been subcontracted or outsourced by the verification body, and
- (vii) the name of the person who acted as the independent reviewer for the verification in accordance with section 139 of these Regulations, and
- (viii) with respect to any outsourced verification work, the scope of the verification, including any gaps in the lifecycle and the percentage of the verification that is outsourced;
(c) with respect to the result of the verification of the application or report,
- (i) the opinion of the verification body referred to in paragraph 154(a), (b) or (c) of these Regulations or the disclaimer referred to in paragraph 154(d) of these Regulations, including the level of assurance applied and the criteria used, and
- (ii) in the case where the verification has resulted in the qualified opinion referred to in paragraph 154(b) of these Regulations, a description of the qualifications and limitations and their possible effects on the application or report;
(d) the address of the office of the Department of the Environment to which the verification report is sent, as well as the name and title of the recipient; and
(e) the signature and location of the verification body as well as the date of the opinion or disclaimer, as the case may be.

2 Any other information that is, in the opinion of the verification body, relevant to the verification.

SCHEDULE 21

(Subsection 136(2))

Contents of Monitoring Plan

1 A list of other systems of tradeable units in which the participant participates and other third-party audit programs with which they comply.

2 A description of the operations to be verified, including a description of

(a) the activities and processes of the operations;
(b) the geographical boundaries within which the operations occur; and
(c) the technologies, facilities and infrastructure that are used to perform the operations.

3 A simplified block diagram of the operations to be verified, including

(a) the feedstock and the fuel, thermal energy or electricity sources that are used in the operations;
(b) the intermediate products and final products that the operations produce;
(c) the mechanical equipment that is used to perform the operations;
(d) the process control instrumentation, including sensors and measurement devices, that are used to monitor the operations;
(e) the sampling locations that are used to monitor the operations; and
(f) a designation for each element of the block diagram.

4 A description of each source of the data to which the application or report relates that includes, if applicable to the source,

(a) its accuracy;
(b) its sampling characteristics; and
(c) the frequency with which data is collected.

5 A description of the data management system that is used to manage the data to which the application or report relates, including

(a) the policies and procedures that ensure data quality, including those that relate to
- (i) data collection and measurement,
- (ii) the emission-reduction quantification methods that were used,
- (iii) reporting,
- (iv) maintenance, inspection and repair of continuous monitoring systems, flow meters, laboratory equipment and other instrumentation used to collect the data, including procedures for deferring their maintenance and inspection,
- (v) contingency plans in the event of a failure of a measurement device or a component of a continuous monitoring system,
- (vi) the keeping of records, including the logbook of measurement device and laboratory equipment repair, calibration and replacement,
- (vii) the training of key personnel responsible for the data management;
- (viii) the frequency of sampling,
- (ix) the laboratory procedures and methods of analysis, and
- (x) the quality control program that is used by the laboratories;
(b) the roles and responsibilities of personnel with respect to the data management system;
(c) its design, including the information technology infrastructure and applications used to manage the data;
(d) its data management controls, including their location, purpose, frequency and type;
(e) the procedures with respect to missing data;
(f) the procedures with respect to non-representative data such as data generated during plant shutdowns or emergencies;
(g) the subcontractors or the software that are used to manage the data;
(h) the security methods that are used to ensure data integrity; and
(i) data back-up procedures.

6 The following information with respect to each measurement device that is used to measure data to which the application or report relates:

(a) its description;
(b) its make, model and serial number;
(c) its location, installation method and approximate date of installation;
(d) its measurement characteristics, including the units of measure, accuracy and lower detection limits;
(e) its maintenance, including the calibration method and calibration frequency;
(f) any postponements in calibration and any supporting documents; and
(g) the frequency with which it provides measurements.

7 Information with respect to the calculations and use of data to which the application or report relates, including

(a) the equations used to
- (i) calculate flows in mass, volume or energy units of measurement,
- (ii) convert units,
- (iii) estimate non-measured parameters,
- (iv) aggregate data, and
- (v) estimate, interpolate or extrapolate data;
(b) any software used to transform the data; and
(c) any statistical methods or techniques applied to transform the data.

8 If the verification is in respect of an application made under section 80 of these Regulations or a report submitted under section 123 of these Regulations, the following information:

(a) an explanation of the processes and methods followed to collect the data used in the application or report, including any supporting documents;
(b) a description of the steps taken, and calculations made, to aggregate the data;
(c) the methodology used to assign volumes, in respect of a fuel, source of electricity or feedstock, for each carbon intensity value; and
(d) the methodology used to monitor and calculate the weighted average of the transportion distance, in respect of a fuel, source of electricity or feedstock, for each transport mode, including any supporting documents.

9 An explanation of the process and methodology that was used to calculate the maximum quantity of a low-carbon-intensity fuel in accordance with subsection 45(1), including any supporting documents and data.

10 If the verification is in respect of a credit-creation report submitted under section 120 of these Regulations, a credit-adjustment report submitted under section 122 of these Regulations or a compliance report submitted under section 127 of these Regulations, a reference to the documents that relate to the quantity of any fuel or energy source that was produced and the sale, purchase or transport of any fuel or energy source.

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Issues: Greenhouse gases (GHGs) are primary contributors to climate change. The largest sources of GHG emissions in Canada are from the extraction, processing and combustion of fossil fuels. In order to meet Canada’s current GHG emission reduction target under the Paris Agreement, and achieve the goal of net-zero emissions by 2050, a number of GHG emission reduction measures have been implemented. While these actions are bringing Canada closer to meeting its climate goals, further action is required.

Description: The Clean Fuel Regulations (the Regulations) will require gasoline and diesel primary suppliers (i.e. producers and importers) to reduce the carbon intensity (CI) of the gasoline and diesel they produce in, and import into, Canada from 2016 CI levels by 3.5 grams of carbon dioxide equivalent per megajoule (gCO₂e/MJ) in 2023, increasing to 14 gCO₂e/MJ in 2030. The Regulations will also establish a credit market whereby the annual CI reduction requirement could be met via three main categories of credit-creating actions: (1) actions that reduce the CI of the fossil fuel throughout its lifecycle, (2) supplying low-carbon fuels, and (3) supplying fuel and energy in advanced vehicle technologies. Parties that are not fossil fuel primary suppliers would be able to participate in the credit market as voluntary credit creators by completing certain actions (e.g. low-carbon fuel producers and importers). In addition, the Regulations repeal the Renewable Fuels Regulations (RFR) but retain the minimum volumetric requirements (at least 5% low CI fuel content in gasoline and 2% low CI fuel content in diesel fuel and light fuel oil) currently set out in the RFR.

Regulatory development: The annual CI reduction requirements have been informed by extensive consultation with industry stakeholders and associations (including the oil and gas sector, low-carbon energy sectors, and industry sectors that use liquid fuels), environmental non-governmental organizations (ENGOs), representatives from provincial and territorial governments, associations representing Indigenous Peoples, administrators of similar regulations in other jurisdictions, and academics. ENGOs and stakeholders in the low carbon energy sectors support the Regulations while some provincial governments and some stakeholders in the oil and gas sector have raised concerns about the costs of compliance. Since the Regulations were first introduced in a discussion paper in February 2017, the Department has made a number of changes to the design of the Regulations in response to stakeholder feedback.

The Regulations are intended to be a flexible, performance-based policy tool that reduces the CI of liquid fossil fuels supplied in Canada. Therefore, the Regulations incorporate, but also improve upon the federal RFR. The Regulations will also be complementary to carbon pricing as they would provide an additional incentive to reduce GHG emissions by reducing the CI of liquid fuels, which are primarily used in the transportation sector, a major source of GHG emissions in Canada.

Cost-benefit statement: Between 2022 and 2040, the cumulative GHG emission reductions attributable to the Regulations are estimated to range from 151 to 267 megatonnes of carbon dioxide equivalent (Mt CO₂e), with a central estimate of approximately 204 Mt CO₂e. To achieve these GHG emission reductions, the modelling conducted for this analysis estimates that the Regulations could result in societal costs that range from $22.6 to $46.0 billion, with a central estimate of $30.7 billion. Therefore, the GHG emission reductions would be achieved at an estimated societal cost per tonne between $111 and $186, with a central estimate of $151. To evaluate the results, a break-even analysis was conducted that compares the societal cost per tonne of the Regulations to the Departmental value of the social cost of carbon (SCC) published in 2016, and to more recently published estimates of the SCC value found in the academic literature. Given that there is a range of publicly available updated estimates of the SCC that well exceed the estimated societal cost per tonne of the Regulations, the Department concludes that it is plausible that the monetized benefits of the Regulations will exceed its costs.

The Regulations will increase production costs for primary suppliers, which would increase prices for liquid fuel consumers (i.e. households and industry users). In addition, credit revenues would decrease the costs of production for low-carbon energy suppliers, which would make low carbon energy sources (e.g. biofuel and electricity) relatively less expensive in comparison. These price effects would lead to decreased end-use demand for fossil fuels and increased end-use demand for lower carbon energy sources, thereby reducing national GHG emissions. To evaluate the direct impact of the Regulations, as well as the effect of relative price changes on Canadian economic activity and GHG emissions, a macroeconomic analysis was completed. When these effects are taken into account, it is estimated that the Regulations will result in an overall GDP decrease of up to $9.0 billion (or up to 0.3% of total GDP) while reducing up to 26.6 Mt of GHG emissions in 2030, using an upper bound scenario where all credits are sold at the marginal cost per credit.

The Regulations will work in combination with other federal, provincial, and territorial climate change policies to create an incentive for firms to invest in innovative technologies and fuels by setting long-term, predictable and stringent targets. The broad range of compliance strategies allowed under the Regulations will also allow fossil fuel suppliers the flexibility to choose the lowest-cost compliance actions available. If the Regulations induce more long-term innovation and economies of scale than projected in the estimates presented in this analysis, then the Regulations could result in lower costs and greater benefits, particularly over a longer time frame.

One-for-one rule: The Regulations will result in annualized net administrative cost increases of about $228,000 for fossil fuel producers and importers. Net annualized administrative costs for renewable fuel producers and importers are estimated at $846,000. Net annualized administrative costs for all other voluntary credit creators are $459,000. Overall, the total net annualized administrative cost increases are estimated at $1.5 million for all stakeholders. The Regulations will be considered an “IN” under the Government of Canada’s one-for-one rule.

Small business lens: The small business lens does not apply to the Regulations as no participants are considered small businesses.

Issues

Greenhouse gases (GHGs) are primary contributors to climate change. The largest sources of GHG emissions in Canada are from the extraction, processing and combustion of fossil fuels. GHG emissions from the oil and gas and transportation sectors account for 26% and 25% of total GHG emissions in Canada, respectively.^{footnote 3} In order to reach Canada’s current GHG emission reduction target to reduce emissions by 40-45% below 2005 levels by 2030 under the Paris Agreement, and achieve the goal of net-zero emissions by 2050, a number of GHG emission reduction measures have already been implemented.^{footnote 4} However, further action is required to meet Canada’s GHG emission reduction targets. In particular, without additional action, it is expected that emissions from Canada’s transportation and oil and gas sectors would continue to increase year-over-year.

Background

Global warming is projected to lead to changes in average climate conditions and extreme weather events. The impacts of climate change are expected to worsen as the global average surface temperature becomes warmer. Climate change impacts are of major concern for society: changes in temperature and precipitation can impact natural habitats, agriculture and food supplies, and rising sea levels can threaten coastal communities.^{footnote 5}

The Government of Canada has committed to taking action on climate change. At the United Nations Framework Convention on Climate Change (UNFCCC) conference in December 2015, the international community, including Canada, adopted the Paris Agreement, an accord intended to reduce global GHG emissions to limit the rise in global average temperature to less than 2°C above pre-industrial levels and to aim to limit the temperature increase to 1.5°C. As part of its Intended Nationally Determined Contribution (INDC) commitment under the Paris Agreement, Canada pledged to reduce national GHG emissions by 40-45% below 2005 levels by 2030.^{footnote 6}

On December 9, 2016, the Prime Minister, along with most first ministers of Canada, agreed to the Pan-Canadian Framework on Clean Growth and Climate Change (PCF). The PCF was developed to establish a path forward to meet Canada’s commitments under the Paris Agreement.^{footnote 7} On November 25, 2016, as part of the PCF, the Government of Canada announced its plan to develop a Clean Fuel Standard (CFS) to reduce Canada’s GHGs by 30 Mt annually by 2030 on a lifecycle basis for fuels used in Canada.^{footnote 8} Since announcing the policy in late 2016, the Department of the Environment (the Department) has engaged broadly with stakeholders on the design of the CFS and a number of formal consultation documents were released, including

a discussion paper published in February 2017, which laid out different approaches from different jurisdictions, and posed technical questions related to the potential applicability of various elements;
a Regulatory Design Paper published in December 2018, which outlined the main design elements and approach of the CFS for liquids;
the Cost-Benefit Analysis (CBA) Framework published in February 2019, which outlined the methodology for the CBA; and
a Proposed Regulatory Approach published in June 2019, which updated and expanded on the December 2018 Regulatory Design Paper;^{footnote 9}
presentations delivered to interested parties and published in June 2020, which provided an update on the design of the upcoming proposed Regulations; and
proposed Clean Fuel Regulations (proposed Regulations), published in the Canada Gazette, Part I, on December 19, 2020.^{footnote 10}

Also in December 2020, A Healthy Environment and a Healthy Economy, Canada’s Strengthened Climate Plan (the Strengthened Climate Plan)^{footnote 11} was published. The plan builds on the efforts that are underway through the PCF. In the context of additional measures proposed in the Strengthened Climate Plan, the scope of the Clean Fuel Regulations (the Regulations) was narrowed to cover only liquid fossil fuels, like gasoline, diesel and oil, which are mainly used in the transportation sector. This is a progression in the design of the Regulations from its initial discussion in 2016, when it was proposed that the new measure would cover liquid, gaseous and solid fuels.

In June of 2021, an update to the Strengthened Climate Plan was published. This document provided an overview of climate actions taken in Canada, with a focus on measures since December 2020. The scope of the Regulations was further refined at this time to eliminate the obligation on heavy fuel oil, light fuel oil and kerosene, and to allow primary suppliers to subtract fuel sold or delivered for space heating from their pool of obligated fuel volumes.

On December 16, 2021, the Minister of the Environment and Climate Change (the Minister) received a mandate letter from the Prime Minister to carry forward whole-of-government effort to reduce emissions, create clean jobs and address the climate-related challenges communities are already facing. This included driving Government’s Climate Plan to meet legislated 2030 climate goals, which incorporates mandating the sale of zero-emission vehicles and setting Canada on a path to achieve an electricity grid with net-zero emissions by 2035. It also included delivering on all policy and fiscal measures outlined in the Strengthened Climate Plan, adopting additional measures to achieve net zero emissions by 2050, and advancing the Emissions Reduction Plan (ERP) to mitigate 40 to 45% of emissions by 2030 from 2005 levels.

The 2030 ERP published in 2022 describes the actions that are already driving significant reductions as well as the new measures that will ensure that Canada continues reducing emissions sector-by-sector to reach its climate target of cutting emissions by 40% below 2005 levels by 2030 and achieving net-zero emissions by 2050. The Regulations are one of the actions described in the ERP that will deliver significant emissions reductions from liquid fossil fuels.

Fossil fuels and fossil alternatives produce different quantities of GHG emissions when the full lifecycle of the fuel is considered, depending on the process used to produce the fuel, the actual composition of the fuel, and the way the fuel is used. The lifecycle of fuel accounts for all emissions connected to the extraction, production, transportation and combustion of a given fuel. Lifecycle-based fuel standards (such as the CFS) are based on lifecycle analysis (LCA) and require lifecycle carbon intensity (CI) calculations, based on the quantity of CO₂ equivalent emissions per unit of energy produced (i.e. gCO₂e/MJ) to assess the different GHG reduction values of fuels.

Generally speaking, CI standards or requirements are designed by assessing the CI values for each fuel using an LCA approach and comparing them to a required CI value that declines each year. Low carbon fuels that have CI values below the required CI value can generate credits, while fuels with CI values above the required CI value generate deficits. Credits and deficits are denominated in metric tonnes of lifecycle GHG emissions. Providers of fuels (the regulated parties) must demonstrate that the total mix of fuels they supply for use in the regulated jurisdiction (national or regional) meets the CI standards for each compliance period (usually a year). Regulated entities meet their compliance obligation by ensuring that the number of credits they earn or otherwise acquire from another party is equal to, or greater than, the deficits they have incurred.

British Columbia and California have implemented standards to lower the CI of fuels (called low-carbon fuel standards or clean fuel standards). Under these standards, requirements are set to reduce the lifecycle GHG emissions intensity of the fuels supplied in a given year by a certain percentage relative to a stipulated baseline year (e.g. 10% by 2020 from a 2010 baseline CI level).^{footnote 12} The sections below describe relevant fuel CI requirements that currently exist in Canada, the United States, and the European Union (EU).

Renewable fuel requirements — Canada

The federal RFR were established in August 2010. They require fossil fuel producers and importers to have an average renewable content of at least 5% based on their volume of gasoline, and an average renewable content of at least 2% based on their volume of diesel fuel and heating distillate oil.^{footnote 13} The purpose of the RFR is to reduce overall GHG emissions from gasoline and diesel fuel, which is primarily used in transportation. There are exemptions for specialty fuels (e.g. those used in aircraft, competition vehicles, military combat equipment), for fuel used in northern regions, for export, for space heating purposes, and for the province of Newfoundland and Labrador. Unlike the Regulations, the RFR does not require reductions in GHG emissions on a lifecycle basis, nor do they contain safeguards to ensure that biofuel production does not adversely affect biodiversity (direct land use change).

Six provinces (British Columbia, Alberta, Saskatchewan, Manitoba, Ontario, and Quebec) already have renewable fuel requirements equal to or higher than the current federal requirements set in the RFR. Most of these provinces have established renewable fuel industries. Some jurisdictions (e.g. Alberta, Ontario) also require that the renewable fuels utilized meet a specific GHG performance standard.

Renewable fuel requirements — United States

Established in December 2005, the United States Renewable Fuel Standard (U.S. RFS) requires increasing annual volumes of renewable fuels to be blended into fossil fuels.^{footnote 14} The U.S. RFS differentiates renewable fuels based on their lifecycle GHG emission reductions, including emissions from indirect land use change. The indirect land use change impacts of biofuels relate to the consequence of releasing more carbon emissions due to land use changes induced by the expansion of croplands for biofuel production in response to the increased demand for biofuels. The annual volumetric requirements are set out for four categories of renewable fuels. The categories are designed to increase the use of renewable fuels with lower GHG lifecycle carbon intensities. Each category must meet a certain GHG reduction threshold (20% for conventional or first-generation renewable fuels, 50% for advanced biofuels, 50% for biomass-based diesel, and 60% for cellulosic biofuel). Fuels with a higher GHG reduction threshold (e.g. cellulosic ethanol) can also be used to help meet the volumetric requirements. In addition to the annual volumetric requirements for a lower GHG reduction threshold (e.g. conventional renewable fuels), the U.S. RFS requires the creation of credits, representing volumes of renewable fuels, and has a credit trading system. Currently, the RFS requires conventional renewable fuel to comprise 11% of transportation fuel, 3% of advanced biofuel, 2% of biomass-based diesel and less than 1% of cellulosic biofuel.^{footnote 15}

Seven states also have renewable fuel requirements: Louisiana, Minnesota, Missouri, Montana, Oregon, Pennsylvania, and Washington.

Fuel CI requirements — British Columbia, California, Oregon and the EU

In January 2010, British Columbia’s Renewable and Low Carbon Fuel Requirements Regulation (RLCFRR) came into effect. The RLCFRR requires reductions in the lifecycle CI of transportation fuels supplied in a given year. In addition, at least 5% of gasoline and 4% of diesel by volume must contain renewable fuel.^{footnote 16} Initially, fuel suppliers were required to progressively decrease the average CI of their fuels to achieve a 9% reduction in 2020 from a 2010 CI baseline.^{footnote 17} In December 2018, British Columbia’s Ministry of Energy, Mines and Petroleum Resources announced in its CleanBC Plan an increase of the CI target to 20% by 2030 relative to 2010 CI levels.^{footnote 18} In July 2020, these amendments to the RLCFRR came into effect.^{footnote 17} To date, British Columbia is the only province with a low carbon fuel standard.

The RLCFRR applies to all fuels used for transportation in British Columbia with the exception of fuel used by aircraft or for military operations. British Columbia’s requirement does not differentiate between crude oil types. Fuel suppliers can comply with the RLCFRR by reducing the overall CI of the fuels they supply, acquiring credits from other fuel suppliers, or by entering into an agreement with the province. Under these agreements, fuel suppliers are able to generate credits based on actions (projects) that reduce GHG emissions through using low-carbon fuels sooner than would have otherwise occurred without the agreed-upon action. Examples of projects supported under credit creating agreements include installing and operating new pumps that supply finished gasoline with at least 15% ethanol or finished diesel with at least 10% biodiesel or 50% hydrogenation-derived renewable diesel.

Adopted in April 2010, California’s Low Carbon Fuel Standard initially required fuel suppliers to reduce the CI of transportation fuels by 10% by 2020, from a 2010 baseline.^{footnote 19} California’s Low Carbon Fuel Standard was readopted in November 2015 to correct for legal deficiencies found in the initial fuel standard while also increasing the stringency of the CI reduction requirement to help meet its original target.^{footnote 20} In July 2020, the California Air Resource Board approved amendments to the Low Carbon Fuel Standard, which require fuel suppliers to reduce the CI of transportation fuels they supply by at least 20% by 2030, from a 2010 baseline. It also added new crediting opportunities to promote zero emission vehicle adoption, alternative jet fuel, carbon capture and sequestration, and advanced technologies to achieve deep decarbonization in the transportation sector.

Oregon’s Clean Fuels Program took effect in 2016 and requires a reduction in the annual average CI of Oregon’s transportation fuels (gasoline and diesel) by 10% from the 2015 level by 2025.^{footnote 21} It prescribes declining maximum CI limits, for each year.

The EU also has a similar policy in place. Established in April 2009, the Fuel Quality Directive requires fuel suppliers to reduce lifecycle GHG emissions from fuels by 10% from 2010 levels by 2020.^{footnote 22} The Fuel Quality Directive works in tandem with the EU Renewable Energy Directive, which stipulates that the share of biofuels in the transportation sector should be 10% (by energy content) for each member country by 2020.^{footnote 23}

Objective

The Regulations are intended to reduce GHG emissions by reducing the lifecycle CI of liquid fossil fuels used in Canada, and thereby the Governor in Council is satisfied that they meet the regulatory requirements as set out in subsection 140(2) of the Canadian Environmental Protection Act, 1999 (CEPA). To achieve this, the Regulations incentivize low carbon fuel uptake, end-use fuel switching in transportation, and process improvements in the oil sector. The Regulations aim to reduce the CI of gasoline and diesel by 14 grams of carbon dioxide equivalent per megajoule (gCO₂e/MJ) by 2030, which represents a decrease of approximately 15% in CI below 2016 levels. The Regulations work in conjunction with other federal, provincial and territorial policies to help meet Canada’s current 2030 GHG emission reduction target under the Paris Agreement, and put Canada on a path towards the goal of net-zero emissions by 2050. In doing so, the Regulations encourage innovation and growth by increasing incentives for the development and adoption of clean fuels and energy efficient technologies and processes.

Description

Subsection 139(1) of CEPA states that no person shall produce, import or sell a fuel that does not meet the prescribed requirements. The Regulations, which have been made under subsection 140(1) and, for the compliance credits regime, under section 326 of CEPA, will implement this prohibition.

Carbon intensity requirements

The Regulations require producers and importers of gasoline or diesel, called primary suppliers, to reduce the lifecycle CI of the gasoline or diesel they produce or import in Canada for use in Canada. Most primary suppliers are corporations that own refineries and upgraders. The Regulations establish annual lifecycle CI limits for gasoline and diesel, expressed in gCO₂e/MJ. This obligation is placed on primary suppliers who domestically produce or import at least 400 cubic metres (m³) of gasoline or diesel for use in Canada. Non-fossil fuels do not have a CI reduction requirement.

The annual lifecycle CI reduction requirements for gasoline and diesel will come into force on July 1, 2023, starting at a 3.5 gCO₂e/MJ reduction in CI for the remainder of 2023 and increasing to a 14 gCO₂e/MJ reduction by 2030 at a rate of 1.5 gCO₂e/MJ per calendar year. Reduction requirements for the years after 2030 will be held constant at 14 gCO₂e/MJ, subject to a review of the regulations and future amendments. The annual CI reduction requirements that primary suppliers must meet for the gasoline and diesel fuels they supply to Canada is the difference between the baseline CI value and the CI limit for gasoline and diesel. Both gasoline and diesel have the same annual CI reduction requirement. The Regulations do not differentiate fossil fuels based on crude oil type, or whether the crude oil is produced domestically or imported into Canada.

A primary supplier’s annual reduction requirement is expressed in tonnes of carbon dioxide equivalent (tCO₂e) and calculated on a company-wide basis, summing up the reduction requirements for gasoline and diesel for each of a company’s production facilities and for their total imports, based on the energy content of each fossil fuel (gasoline and diesel). The Regulations also incorporate the minimum volumetric requirements that are currently set out in the federal RFR, requiring a minimum 5% low-carbon-intensity fuel content in gasoline and 2% low-carbon-intensity fuel content in diesel fuel.

The Regulations set out the baseline CI values for gasoline and diesel produced in and imported for use in Canada. These values are Canadian average lifecycle CI values, calculated from the Department’s Fuel Lifecycle Assessment Model. This means that each type of fossil fuel (gasoline and diesel) is assigned the same national average value. GHG emissions from all stages in a fuel’s lifecycle are included in the determination of the baseline CI values.

Exemptions and exclusions

The Regulations include a limited number of exemptions and exclusions from the annual reduction requirements for gasoline and diesel. The Regulations do not apply to aviation gasoline, fossil fuel exported from Canada, fossil fuel used in scientific research, and fossil fuel sold or delivered for use in competition vehicles. In addition, certain volumes can be excluded from the primary supplier’s pool of obligated fuel volumes if appropriate records are established. These include gasoline or diesel sold or delivered for a use other than combustion, produced in a facility for use in that facility (other than in mobile equipment), sold or delivered for use in a marine vessel with a non-Canadian port destination, sold or delivered for the purpose of space heating and sold or delivered for non-industrial use or power generation in remote communities. Remote community is defined as a geographic area that is not serviced by an electrical distribution network that is under the jurisdiction of the North American Electric Reliability Corporation or by a natural gas distribution system.

Establishment of a credit market

The Regulations establish a credit market, where each credit represents a lifecycle emission reduction of one tonne of CO₂e. For each compliance period (typically a calendar year), a primary supplier would demonstrate compliance with their reduction requirement by creating credits or acquiring credits from other creators, and then using the required number of credits for compliance. Once a credit is used for compliance, it is cancelled and can no longer be used.

Volumetric requirements

To meet the minimum volumetric requirements incorporated from the federal RFR, each primary supplier is required to demonstrate for each compliance period that, of the total number of compliance credits it retires for compliance, a minimum (equivalent to 5% of its gasoline pool and 2% of its diesel and light fuel oil pool) is from low-CI fuels such as ethanol or biodiesel. These compliance credits are part of the total credits used to meet reduction requirements, but the same compliance credit cannot be used to meet the 2% and 5% requirements respectively. Primary suppliers who have surplus compliance units under the RFR are able to convert these units into credits under the Regulations after the end of the final compliance period of the RFR.

Voluntary credit creators

Parties that are not primary suppliers are able to participate in the credit market as voluntary credit creators. In addition to the primary suppliers that are subject to the CI reduction requirements in the Regulations, other possible credit creators include low carbon fuel producers and importers (e.g. ethanol producer), electric vehicle charging site hosts or network operators, fuelling station owners or operators, as well as parties upstream or downstream of a refinery (e.g. an oil sands operator).

Credit creation categories

Credits may be created by primary suppliers or other voluntary credit creators who take one of the following actions:

Compliance Category 1: actions throughout the lifecycle of a liquid fossil fuel that reduce its CI (such as carbon capture and storage) through GHG emission reduction projects;
Compliance Category 2: supplying low CI fuels (such as ethanol); or
Compliance Category 3: end-use fuel switching in transportation (when an end user of fuel changes or retrofits their combustion devices to be powered by another fuel or energy source, such as electricity in transportation).

Compliance Category 1

This category recognizes actions that reduce a liquid fossil fuel’s CI through GHG emission reduction projects to create credits. Credits can be created by the project proponent as of the date the Minister recognizes the project. Projects can include an aggregation of reductions from multiple sources or facilities, and no minimum emissions reduction threshold is set. The number of credits created is determined by a quantification method, which specifies the eligibility criteria for the project as well as the approach for quantification. Quantification methods would be maintained outside of the Regulations and developed by a team of technical experts, including departmental representatives, and reviewed by a broader consultative committee that includes stakeholders in industry, academia, and other technical experts.

The Department is providing quantification methods for various project types, starting with the following list:

CO₂ capture and permanent storage;
low-CI electricity integration;
enhanced oil recovery with CO₂ capture and permanent storage;
co-processing in refineries; and
low-CI hydrogen integration.

This work would take into consideration existing emission reduction accounting methodologies or offset protocols in other jurisdictions. The Department has developed a generic quantification method for projects for which there is no applicable quantification method. Projects such as energy efficiency, combined heat and power, electrification and methane reductions could be recognized under the generic quantification method provided they meet the eligibility criteria.

To be able to create credits under the Regulations, a project must generate emission reductions that are real and incremental (i.e. additional) to a defined base case. Projects create credits for the portion of the fossil fuel and crude oil that is used in Canada (i.e. exported portion of products are not eligible for credit creation). The base case is defined in the quantification method for each project type. The generic quantification method predefines the base case for some foreseen project types or provides guidance on how to determine the baseline for other project types. In the event that a specific quantification method for a project type is developed during the credit creation period of a project recognized under the generic quantification method that covers the project’s actions, an application may be made to have the project recognized under the specific quantification method.

Facilities in jurisdictions outside of Canada have a mechanism to have their projects recognized. Jurisdictions outside Canada that wish to have projects recognized under the Regulations will be able to enter into an agreement with the Department to ensure their projects are comparable to Canadian projects in effectiveness and meet the Regulations’ objectives. The quantification methods apply to projects conducted in Canada, but can be adapted for other jurisdictions as part of this mechanism. Credits from emissions reductions projects outside Canada must be prorated based on the portion of liquid fossil fuel or crude oil supplied to Canada.

All eligible projects must reduce the CI of a liquid fossil fuel along its lifecycle, achieve incremental GHG emission reductions, and must have begun to reduce, sequester, or use CO₂e emissions on or after July 1, 2017. Project proponents first apply to the Department to have a project recognized prior to credit creation. Each year, information (as specified in the appropriate quantification method) will be required to be reported to the Department, accompanied by a third-party verification report and a verification opinion. Credits are created annually for 10 years for emission reduction projects, except for carbon capture and storage projects, where credits are created annually for 20 years and co-processing in refineries, for which there is no end to the crediting period similar to other low-CI fuels. In addition, projects with a finite crediting period may be renewed a single time for an additional 5 years after the initial crediting period, provided an applicable quantification method still exists at the time of renewal.

Compliance Category 2

This category encompasses credits that are created under the Regulations for low CI fuels produced or imported in Canada. Low CI fuels are fuels, other than the fossil fuels, that have a CI equal to or less than 90% of the credit reference CI value for the fuel. Most low CI fuels available on the market are forms of biofuels, such as ethanol. Other low CI fuels include synthetic fuels, such as those made from the CO₂ captured from the atmosphere as a result of direct air capture or syngas generated from any biomass resource that could also be employed to make new low CI fuel products under a circular economy approach.

All low CI fuels supplied to the Canadian market, including fuels used to comply with existing federal and provincial renewable fuel regulatory requirements and British Columbia’s RLCFRR, are able to create credits under the Regulations. Credits may be created by the producers and importers of liquid and gaseous low CI fuels as of the date of registration of the Regulations. Credits for low CI fuels are created based on the amount of low-carbon fuel supplied to the Canadian market annually (in MJ) and the difference between the lifecycle CI of the low CI fuel and the credit reference CI value for the fuel. In order to create credits, a low CI fuel producer or foreign supplier is required, in most cases, to obtain an approved CI value for each low CI fuel that they produce or import. The Regulations require the use of either the Fuel Lifecycle Assessment (LCA) Model to calculate facility-specific CI values using facility-specific data, or the use of default values available in the Regulations.

A Fuel LCA Model is provided by the Department to support the implementation of the Regulations. Fuel producers and foreign suppliers are able to use the model to determine CI values once they have 24 months of operating data. They may use a provisional CI value using the model with only 3 months of data, until 24 months of data is available. Facilities with less than 3 months of operating data for a low CI fuel need to use prescribed default values. In most cases, fuel producers are required to submit an application to the Minister for approval of each fuel’s CI, as well as to submit an annual CI Pathway Report. Starting in 2025, credits will be adjusted annually based on the CI Pathway Report. If the CI in the annual CI Pathway Report is higher than the approved CI by an amount exceeding the materiality threshold for CI, the equivalent number of credits created in excess will be removed from the account of the credit creator and the CI is no longer valid. Conversely, if the CI determined in the CI Pathway Report is lower than the approved CI, additional credits may be created.

As noted above, the Regulations allow the creation of credits from the production of low CI fuels produced from biomass-based feedstocks. To prevent adverse impacts on land use and biodiversity stemming from the increased harvest and cultivation of these feedstocks, the Regulations establish land-use and biodiversity (LUB) criteria. Only low CI fuels made from biomass feedstock (biofuels) that adhere to the LUB criteria are eligible for compliance credit creation. These criteria apply to feedstock regardless of geographic origin. The criteria do not apply to feedstock that is not biomass (e.g. fuel made from direct air capture) or a biomass feedstock that has a lower risk on land use and biodiversity (e.g. municipal solid waste).

The LUB criteria are separated into requirements specifically for forest feedstock, those specific for agricultural feedstock, and those that apply to all feedstock. These criteria also impose requirements for supply chain declarations (used to trace eligible material from the feedstock harvester to the low CI fuel producer) and material balancing (used to permit physical mixing of eligible and non-eligible feedstock). The onus for demonstrating criteria adherence rests with the low CI fuel producers, but compliance with the criteria need to be demonstrated at the feedstock producer level or through an approved certification scheme.

Compliance Category 3

This compliance category covers fuel or energy to advanced vehicle technologies which enables credit creation for changing or retrofitting a fossil fuel combustion device to be powered by another fuel or energy source, such as electric vehicles (EVs). This does not directly reduce the CI of fossil fuels but reduces GHG emissions by displacing gasoline or diesel used in transportation by fuels or energy sources with lower CIs. Credits may be created as of the date of registration of the Regulations by the owners or operators of fuelling stations that supply fuels for transportation uses (natural gas, renewable natural gas [RNG], propane, renewable propane), by the producers and importers of low CI fuels (RNG and renewable propane) used for transportation purposes, by the owners or operators of fuelling stations for dispensing hydrogen to hydrogen fuel cell vehicles or other vehicles, by charging network operators for residential and public charging of EVs, and by charging site hosts for private or commercial charging of EVs. Credits for residential charging of EVs will be phased out by the end of 2035 for charging stations installed by the end of 2030. Any residential charging station installed after the end of 2030 will not be eligible for credits. The Regulations require charging network operators to reinvest 100% of the proceeds from the sale of credits created by residential and public EV charging. The revenue must be reinvested into two available categories of actions: either reducing the cost of EV ownership through financial incentives to purchase or operate an EV, or expanding charging infrastructure in residential or public locations, including EV charging stations and electricity distribution infrastructure that supports EV charging.

Satisfying annual reduction requirements

In order to meet their obligation, primary suppliers are required to use credits to satisfy their annual reduction requirement. There is no limit to the number of liquid compliance credits that may be used by a primary supplier for the purposes of compliance. However, a primary supplier may use gaseous compliance credits in order to satisfy up to 10% of its total reduction requirement annually. These credits can be created in respect of the production or import of low CI gaseous fuels or GHG emission reduction projects that involves the production or import of co-processed low-CI gaseous fuels. Additionally, a primary supplier may use credits created under the generic quantification method in order to satisfy up to 10% of its total reduction requirement annually.

Compliance flexibilities exist to help mitigate compliance cost and ensure credit supply. A primary supplier may use the compliance fund mechanism by contributing to an eligible “registered” funding program in order to satisfy up to 10% of its annual reduction requirement. The credit price under this mechanism is set in the Regulations at $350 in 2022 (consumer price index [CPI] adjusted) per compliance credit. The credits created by these investments cannot be traded and will expire if not used for that compliance period. Primary suppliers may create credits by contributing to a registered funding program between January 1 and July 31. Additionally, primary suppliers may contribute between October 15 and November 30 following the end of a compliance period if required.

Funds or programs within a fund that reduce CO₂e emissions may be eligible to become a registered fund. The fund or program must operate in Canada, provide funding for projects or activities that support the deployment or commercialization of technologies or processes that reduce CO₂e emissions, and provide publicly available annual audited reports. Any contributions to the fund must be used for projects or activities that reduce emissions within a five-year period from the time the contribution is made.

For primary suppliers unable to satisfy their reduction requirement by July 31 following the end of a given compliance period, a market-clearing mechanism that facilitates credit acquisition by primary suppliers is also available. The Regulations set a maximum price for credits acquired, purchased or transferred in the credit clearance mechanism (CCM) at $300 in 2022 (CPI adjusted) per compliance credit. If there are not sufficient credits available in the CCM for all primary suppliers to satisfy their outstanding reduction requirement, each primary supplier is eligible to acquire a prorated amount of the available credits. If the CCM is depleted of all pledged credits, primary suppliers with a shortfall must contribute to a registered funding program, up to the maximum of 10% of their CI reduction requirement.

After satisfying those obligations, a primary supplier can carry forward up to 10% of its reduction requirement into a future compliance period, with a maximum deferral of five years. An interest of 5% is applied annually to any deferred amount.

Reporting requirements

The Regulations require the reporting of all credit trades, and all parties are required to register and keep records. Annual compliance reporting to the Minister is required for all primary suppliers and credit creators. The Regulations include verification requirements. Most significantly, regulated parties are required to obtain from an independent, accredited third-party verification body a report stating whether the information submitted is complete, compliant with the requirements, and credits and obligations are accurate and without material error. The Regulations require most submitted applications and reports to be verified by a third party, with accompanying verification reports.

Coming into force

The Regulations come into force on the date the Regulations are registered. As of this date, credit creators will be able to register and start creating credits. The annual reduction requirements come into force on July 1, 2023. The final compliance period for the federal RFR is 2022, with the final reporting and true-up period for the RFR occurring in 2023. The RFR will then be repealed on September 30, 2024.

A review of the Regulations will be undertaken. This review will conclude five years after the Regulations come into force, and will include a review of provisions on CI limits and credit creation opportunities.

Regulatory development

Since 2017, the Department has conducted hundreds of hours of group meetings, technical webinars and bilateral meetings on development of the Regulations. Stakeholders in these sessions included industry (fossil fuel producers and suppliers, low-carbon fuel producers and suppliers, emission-intensive and trade-exposed (EITE) sectors), and representatives from various other industry groups, provinces and territories, Indigenous Peoples, environmental non-governmental organizations (ENGOs), administrators of similar programs in other jurisdictions and academics.

Pre-CG1 consultation process

The Department chaired several committees, which provided a forum for active engagement with stakeholders. These committees included a Multi-Stakeholder Consultative Committee (MSCC), a Technical Working Group (TWG), and a task group specifically examining impacts to EITE sectors. Provinces and territories have also been heavily engaged in the consultations on the proposed Regulations and were participants on various committees, including a Federal-Provincial-Territorial Working Group. Engagement via these committees helped inform the more detailed aspects of the design of the proposed Regulations.

Various consultation documents were published between 2017 and 2020 to gain initial views from stakeholders on key regulatory design elements and to receive feedback on the full set of requirements and credit creation opportunities:

February 2017: Discussion Paper on the Clean Fuel Standard
December 2017: Regulatory Framework
December 2018: Regulatory Design Paper
February 2019: Cost Benefit Analysis Framework for the Clean Fuel Standard
June 2019: Proposed Regulatory Approach

Hundreds of comments were received and analyzed to inform the development of the proposed Regulations. All publications mentioned above are accessible at the Government of Canada’s Clean Fuel Standard webpage.

In June 2020, the Minister announced to the TWG that the stringency of the proposed Regulations would be increased in order to ensure that the Regulations remain on track to deliver significant GHG emission reductions by 2030. Other updates included more details on quantification methods, land-use and biodiversity (LUB) criteria, the compliance fund mechanism and the CCM, and a review process of the Regulations. The Department also updated the fossil fuel baseline values based on LCA experts and TWG comments. Details of the feedback received through these consultations along with responses from the Department can be found in the Regulatory Impact Analysis Statement published in the Canada Gazette, Part I on December 19, 2020.

Post CG1 consultations

Analysis and responses to stakeholder feedback received on the proposed Regulations published in the Canada Gazette, Part I

Overview

The proposed Regulations, published in the Canada Gazette, Part I on December 19, 2020, initiated a 75-day comment period that ended in March 2021. The proposed Regulations were also posted on the Department’s CEPA Environmental Registry website to highlight the consultation period to interested parties, which were invited to submit written comments. The Department emailed all stakeholders that had been involved in previous consultations on the Regulations. Global Affairs Canada sent a notification to the World Trade Organization to inform other countries of the publication of the proposed Regulations and the comment period.

Informational presentations for different aspects of the proposed Regulations were shared with stakeholders. This was followed by four question and answer sessions for the Technical Working Group, and one question and answer session for the MSCC. These sessions were held in January 2021, before the end of the 75-day comment period.

The Department received extensive comments from over 180 stakeholders, representing over one thousand pages of submissions. The comments were received from a broad range of domestic and international stakeholders from the oil and gas sector, low-carbon fuel sector, renewable fuel feedstock providers, zero emissions vehicle manufacturing and fuelling sectors, other industrial sectors such as EITEs and aviation and railway transportation sectors, environmental non-governmental organizations, academics, think tanks, and an Indigenous organization. Overall, stakeholders were supportive of the proposed Regulations and its environmental objectives.

Primary suppliers were generally supportive of the proposed Regulations, but were concerned about the coming into force date, the availability of tools required to implement the Regulations (e.g. quantification methods, Fuel LCA Model) prior to the publication of the final Regulations, as well as the stringency of reduction requirements and the risk of credit shortage. Provinces largely echoed comments from primary suppliers. Provinces also commented extensively on the LUB criteria and expressed a desire for the Department to provide provinces with certainty that existing provincial legislation would be recognized under the Regulations as sufficient for meeting the LUB criteria. Low-carbon fuel producers, while supportive of the proposed Regulations, expressed concerns that the signal for renewable fuel production will be too small and recommended that limits should be imposed to ensure a stronger signal (e.g. limits on credit flexibilities, backstop provisions to ensure minimum credits are created from Compliance Category 2, supplying low-carbon fuels, and Compliance Category 3, supplying fuel or energy to advanced vehicle technologies). Along with renewable fuel feedstock providers, they also recommended legislative recognition under the LUB criteria for provinces and the U.S. be provided prior to the publication of the final Regulations.

Reduction requirements, scope and timelines

Scope

A vast majority of stakeholders were supportive of the decision to reduce the scope of the requirements to liquid fuels only, which was announced with the publication of the proposed Regulations. However, a small number of provinces and stakeholders in the low carbon-intensity fuel and feedstock industry noted that the absence of CI reduction requirements for gaseous and solid fossil fuels would result in the loss of an economic opportunity.

A number of stakeholders asked for a further reduction in the scope of the Regulations. In particular, several stakeholders, including primary suppliers, some provinces and non-governmental organizations, suggested that changes be made to address the disproportionate impact on consumers relying on home heating oil. Some stakeholders suggested that the scope of the Regulations be reduced to transportation fuels only, while others proposed to exempt the liquid fossil fuels used by EITE industrial sectors. The Indigenous organization that submitted comments supported reinstating the gaseous and solid fossil fuel requirements.

To address these concerns and in the context of the continued increase to the carbon price, the scope of the Regulations has been narrowed to gasoline and diesel, liquid fossil fuels used predominately in transportation. The reduction requirements for heavy oil, light oil and kerosene were removed. An exclusion was added for fuel used in space heating. Other parts of the Regulation were also adjusted to ensure consistency with the reduced scope, such as removing crediting opportunities for emission-reduction projects conducted along the lifecycle of gaseous and solid fossil fuels.

The Regulations provide an exclusion for liquid fossil fuels used for power generation in remote locations. This change is in recognition of the challenges with supplying low carbon-intensity fuels in remote locations, in line with the exclusion for fuels used in remote communities and with the narrowing of the scope to liquid fossil fuels used mainly in transportation.

Coming into force

A number of primary suppliers and provinces expressed concerns with the proposed coming into force date. One of the key concerns was that key tools needed to implement the Regulations (e.g. the Fuel LCA model, the quantification methods) would not be made available by the Department sufficiently in advance of the coming into force. As such, regulated parties and voluntary credit creators would not have enough time to undertake compliance and credit project planning prior to the coming into force of the Regulations.

To address some of these concerns, the CI reduction requirements in the final Regulations will come into force on July 1, 2023, instead of December 1, 2022. Credit creation would begin as of the date the Regulations are registered. This was done in order to allow credit creators approximately one year for early credit creation prior to the coming into force of the annual reduction requirements.

Annual carbon intensity reduction requirements

A number of primary suppliers have expressed concerns regarding the overall stringency of the proposed Regulations and on the trajectory of the annual CI reduction requirements. On the other hand, some non-government organizations, low CI fuel producers and EV charging stakeholders recommended more stringent reduction requirements, especially in the early years.

In March 2022, the Department proposed increasing the CI reduction target from 12 to 14 gCO2e/MJ in 2030, which represents a decrease of approximately 15% in CI below 2016 levels. The initial CI reduction requirement was changed from 2.4 gCO2e/MJ in 2022, increasing annually by 1.2 gCO2e/MJ, to 3.5 gCO2e/MJ in 2023, increasing annually by 1.5 gCO2e/MJ. These changes ensure that the final Regulations send a strong signal to the market for new, clean investments. Since the publication of the proposed Regulations, the number and impact of complementary measures the Government has announced or implemented has increased significantly. In this context, the increased target and trajectory of the final Regulations is needed to continue delivering significant incremental reductions that would help Canada meet its 2030 emissions reductions target of 40 to 45 percent reduction below 2005 levels and net-zero emissions by 2050. This proposal was communicated to stakeholders via an information session open to the MSCC as well as other interested parties. Generally, stakeholders understood the rationale for increasing the stringency and were supportive of moving forward with finalizing the Regulations.

Compliance Category 1

Crediting period

Some primary suppliers and provinces expressed concerns about the requirements related to the crediting period for emission-reduction projects under Compliance Category 1. For example, some stakeholders opposed the rule that a project would cease to receive credits if the activity it undertakes becomes required under federal or provincial legislation. These stakeholders recommended that the crediting period, once established, should not be modified even if the action becomes required by legislation.

Other stakeholders recommended that the Department remove the crediting period limit – which was set at 20 years for carbon capture and storage projects and at 10 years for other project types, with a potential 5-year renewal – meaning that projects would continue to create credits as long as they are operational.

The Department did not modify the crediting period requirements in the final Regulations. The Department considers that these requirements are necessary to ensure project types remain additional. Furthermore, the Department had already extended the crediting period for the proposed Regulations compared to previous drafts to provide improved investment certainty for investors.

Additionality criteria

For all quantification methods other than the generic method, additionality would be assessed during the development of the quantification method at the project type level and would take into account many factors, including whether an action is required by another Canadian law or regulation; technological and financial barriers; and, the market penetration rate of the technology or practice. Quantification methods would be periodically reviewed for additionality and maintained, modified or withdrawn as activities evolve. The additionality assessment is described in the Quantification Method Development Guidance Document. This document was published along with the proposed Regulations and was part of the consultations. Several stakeholders commented on the additionality criteria used in this assessment. Some stakeholders, including some primary suppliers and some provinces, asked that the Department make the criteria less stringent, for example by increasing the penetration rate used to determine whether a project type is additional or by removing the additionality criteria altogether. Other stakeholders, such as environmental non-governmental organizations, recommended making the additionality criteria more stringent by, for example, using a financial test to determine additionality even when the penetration rate is lower than 5% or 5 facilities.

The Department did not change the criteria used in the additionality assessment for the development and review of specific quantification methods. These criteria are needed to ensure the Regulations result in real emissions reductions. Earlier changes to the criteria already made the additionality test less burdensome for sectors with few entities. For example, adding the possibility of demonstrating additionality by using a penetration rate of no more than five facilities having adopted a technology in a given sector provides more flexibility in the assessment of additionality.

Trade

Several stakeholders commented on the treatment of imported and exported fossil fuels under the proposed Regulations.

Regarding imported fossil fuels, a number of stakeholders in the oil and gas sector commented on the requirement that emission-reduction projects be conducted in Canada in order to be eligible for credit creation under the Regulations. These stakeholders asked that emission-reduction projects conducted partially and/or completely outside Canada also be recognized for credit creation.

The final Regulations enable credit creation for emission-reduction projects at foreign facilities that produce liquid fossil fuels or crude oil, for the portion of fuel or crude oil supplied to Canada. An agreement will have to be in place between the Department and the foreign jurisdiction where the project is conducted to ensure projects from that jurisdiction are comparable to Canadian projects in effectiveness and meet the objectives of the Regulations. This will ensure credit creation opportunities align with the objective of the Regulations, which is to reduce emissions for fuels used in Canada.

A number of stakeholders from the low-CI fuel sector, EV charging industry, and ENGOs expressed that emission reduction projects should not create credits for the portion of fossil fuels or crude oil that is exported. Regulated parties expressed concern about a related issue, specifically, a large supply of credits from carbon capture and storage projects in the oil and gas sector suppressing credit price.

For the final Regulations, the ability for emission reduction projects to create credits for the portion of fossil fuels or crude oil that is exported has been removed from the Regulations. This reinforces the policy objective to reduce emissions from fuels used in Canada, while also bringing treatment of exported fossil fuels in line with the treatment of exported low-CI fuels, which are not credited under the Regulations. Low carbon fuel standards in other jurisdictions also do not credit actions associated with exported fossil fuels or crude oil.

Generic quantification method

Many stakeholders commented on the requirements related to the generic quantification method. Several stakeholders, including stakeholders from the oil and gas sector, other industrial sectors and provinces, wanted more flexibility. In particular, they asked for the removal of the 10% limit on credits from the generic quantification method that can be used annually to meet reduction requirements. Some stakeholders, such as renewable fuels industry members and non-governmental organizations, requested more stringency, for example by decreasing the 10% limit or by increasing additionality requirements. Other stakeholders suggested improving clarity on the use of the generic quantification method.

Several sections have been added to the Regulations to clarify the rules applying to the use of the generic quantification method as well as the process and conditions to transition from the generic quantification method to a specific quantification method.

However, the Department did not change the 10% limit. Placing a credit limit of 10% while applying separate and more streamlined additionality criteria at the project level for the generic quantification method provides compliance flexibility while mitigating risks associated with the streamlined additionality assessment. In addition, requests can be made to the Department for the development of a new specific quantification method for a project type that is considered additional. When a new specific quantification method is adopted, projects covered under the generic quantification method can transition to the new specific quantification method and the credits created in accordance with this new specific quantification method would not be subject to the 10% limit.

Hydrogen

Several primary suppliers and a province have advocated for consistent treatment of hydrogen regardless of where it is produced (i.e. standalone hydrogen production facility versus a refinery). They have also recommended that opportunities for hydrogen as a fuel and feedstock be expanded and prioritized under the Regulations, including by prioritizing the development of a hydrogen quantification method.

For standalone hydrogen plants supplying low-CI fuel or hydrogen used as an energy source in fuel cell vehicles, the Department simplified the approach by including both combustion emissions and process emissions that are captured for CCS or EOR in the determination of the CI of hydrogen using the Fuel LCA Model. In the proposed Regulations, captured combustion emissions were credited under the quantification method for CO2 capture and permanent storage. In addition, the Department is also working on developing a hydrogen-specific quantification method with expert reviewers to allow additional credit creation opportunities for hydrogen. The final quantification method is anticipated in summer 2022.

Compliance Category 2

Carbon capture and storage at low-CI fuel production facilities

Similar to comments provided regarding emission-reduction projects in the oil and gas sector, many stakeholders in the low-CI fuel and the oil and gas sectors asked for the recognition of carbon capture and storage projects undertaken at low-CI fuel production facilities outside Canada for credit creation under the Regulations. Several of these stakeholders also recommended that credit creation for this project type be calculated with the Fuel LCA Model instead of a quantification method.

In response to these comments, the Regulations will recognize carbon capture and storage projects at low-CI fuel production facilities outside Canada. Reductions from these projects will be incorporated in the CI of the low carbon-intensity fuel and will be calculated via the Fuel LCA Model. The reductions associated with CCS and EOR will be included in the Fuel LCA Model in 2024 when a new version of the Fuel LCA Model will be published for the Regulations. At that time, low-CI fuel producers would be able to request a credit adjustment for any amount of fuel supplied in Canada since the registration of the Regulations or the start of the CCS or EOR projects, if the projects start after the registration of the regulations. In order to be incorporated in the CI, the CCS and EOR project would have to be conducted in a jurisdiction that has relevant regulations in place to ensure permanent storage.

Land use and biodiversity criteria

Legislative recognition

Several stakeholders in Canada and in the U.S., including provinces, renewable fuel producers and feedstock producers, argued that crops grown in Canada and the U.S. already meet strict environmental standards and thus they should automatically be granted aggregate compliance with the LUB criteria. Alternatively, if the Department was not able to provide this automatic aggregate compliance, these stakeholders argued that the Department should develop a framework to recognize if provinces and the U.S. meet LUB criteria. They also asked that the Department indicate whether provincial and U.S. legislation would be recognized as meeting the criteria in advance of the publication of the final Regulations.

The Department undertook a high-level review of provincial and territorial legislations and met with provinces and territories to discuss its findings and seek feedback.

The Regulations enable governments to apply to the Minister to be recognized as meeting one or all criteria by referencing existing national and/or sub-national (e.g. provinces, territories, states) legislations, regulations, or legal obligations as defined by binding agreements. National or sub-national jurisdictions would have to apply to the Minister to be recognized as meeting one or all criteria by citing an existing equivalent national or sub-national legislation, or other government imposed legal requirement.

Certification schemes

Several comments were received from provinces, low-CI fuel producers and feedstock providers regarding certification schemes for LUB criteria. For example, some stakeholders asked that the Department accept existing certification schemes, regardless of whether they align with LUB criteria. Other stakeholders recommended that the Department streamline the regulatory burden when establishing certification schemes that meet LUB criteria. It was also suggested that the potential for site visits for the purposes of verification be removed when establishing certification schemes that meet LUB criteria.

Where certification schemes meet accreditation standards outlined in the Regulations, certification bodies will be able to apply to the Minister to have the certification scheme recognized as meeting one or more LUB criteria.

Additional feedstock exemption

A number of provinces commented on additional types of feedstock that could be exempted from the LUB criteria. These feedstock types include feedstocks from damaged crops and primary residues (e.g. the corn stalk in the case of corn).

After considering these comments, the Department determined that agricultural and forest residues, damaged crops, and forest biomass from fire prevention and protection activities were of low concern regarding impacts on land use. As such these feedstock types have been moved to a category of feedstocks subject to reduced LUB provisions.

Compliance Category 3

Change default credit creator for electric vehicle charging

The proposed Regulations identified charging network operators as the default credit creators for residential and public electric vehicle charging, and charging site hosts for electric vehicle charging that is neither residential nor public. Stakeholders from various sectors (e.g. auto manufacturers, charging network operators, utility companies) commented that the Department should change the default credit creator for residential and public electric vehicle charging to automakers, utilities, or charging site hosts, while others were in favour of maintaining charging network operators as the default credit creators for residential and public electric vehicle charging.

For the final Regulations, the Department has not changed these proposed default credit creators for electric vehicle charging, as this approach provides flexibility by enabling any company to operate as a network operator alone or through investments or partnerships for residential and public charging. Naming one type of credit creator as the default reduces the risk of double counting electricity that could otherwise result from multiple potential credit creators. Additionally, this approach simplifies regulatory requirements and reduces burden, as charging network operators generally operate at a large scale (e.g. nationwide or province-wide), and maintain ownership of the data associated with charging activities. The typical national/provincial scale of charging network operators also provides additional opportunities for public charging expansion by collaborating with site hosts who otherwise may not have the scale or operational capacity to quantify their charging quantity, register and report under the Regulations, trade those credits to other participants, and meet revenue reinvestment requirements.

Charging site hosts are able to create credits for their electric vehicle charging that is neither residential nor public (e.g. commercial applications) without revenue reinvestment requirements. This enables the revenue from credits to incentivize further investment in electric vehicles or their EV charging infrastructure.

Allow revenue investment to cover administrative costs related to the Regulations

Several stakeholders from the auto manufacturing industry, electric vehicle charging industry and other fuel suppliers commented on the revenue reinvestment requirements of the proposed Regulations, which stated that credit revenues from residential and public electric vehicle charging ought to be reinvested to further incent the adoption of zero-emission vehicles. These stakeholders asked that the revenue reinvestment requirements be modified to cover administrative costs related to the Regulations.

The final Regulations do not allow for the revenue reinvestment requirements to include administrative costs. These reinvestment requirements are meant to help increase access to charging infrastructure and to reduce operating costs for electric vehicle drivers as a benefit to those who made investments in electric vehicles.

Residential electric vehicle charging credit creation phase out

Several stakeholders have requested to remove or extend the time frame for the phase out of compliance credit creation from residential charging of electric vehicles.

During consultations in June 2020, the Department proposed to phase out residential electric vehicle charging credits by 2030. However, the proposed Regulations extended 100% of residential electric vehicle charging credits to the end of 2035 for charging stations installed before the end of 2030 and residential charging stations installed after 2030 would not be eligible for credit creation.

The final Regulations maintain the scheduled phase out of credit creation for residential charging, as the number of credits created from electric vehicle charging will increase rapidly as more electric vehicles are adopted in Canada. All credits created from supplying fuel or energy to advanced vehicle technologies are considered non-incremental emissions reductions from the Regulations, so any additional delay in the phase-out of residential electric vehicle charging credits would lead to fewer incremental actions.

Stationary end-use fuel switching

A large variety of stakeholders shared their views on the possibility of allowing credit creation for stationary end-use fuel switching (e.g. switching from heating oil to wood pellets for home heating), which was not included in the proposed Regulations. Many provinces, EITEs, solid and gaseous low-carbon fuel producers as well as industry stakeholders recommended that credit creation from stationary end-use fuel switching be allowed by the Regulations while a few stakeholders from the petroleum sector and low-carbon fuel sector, as well as an ENGO, opposed this idea.

Considering the decision to reduce the scope of the final Regulations to fuels mainly used in transportation, the Regulations do not provide credit creation opportunities for stationary end-use fuel switching.

Credit and trading system and flexibility mechanisms

Compliance Fund Mechanism

Several comments were received on the Compliance Fund Mechanism. Many stakeholders commented on the 10% limit set on the amount of the annual reduction requirement that can be met by contributing to an emissions reduction funding program. A number of stakeholders, including provinces and primary suppliers, expressed that this limit was too low whereas other stakeholders, including low carbon-intensity fuel producers and environmental non-governmental organizations, stated that the limit was too high.

Some stakeholders also commented on the price set for contributing to an emissions reduction funding program. Comments were received from low CI fuel producers, environmental non-governmental organizations as well as stakeholders in the electric vehicle sector and were supportive of maintaining the proposed price at $350/tonne.

The Regulations maintain both the 10% limit on the amount of the annual reduction requirement that can be met by contributing to an emissions reduction funding program at $350 in 2022 dollars per compliance credit (CPI adjusted). This limit along with the corresponding price are expected to strike the right balance between providing a signal for investments in low-carbon fuels while also addressing risk of credit shortage.

Obligation deferral

Numerous comments were received regarding obligation deferral. Several stakeholders from the petroleum sector asked for a relaxation of parameters regarding obligation deferral, such as an increase of the 10% limit, a reduction of the 20% annual interest rate, and/or an increase of the two-year period during which a deficit can be carried forward. Some stakeholders also from the petroleum sector asked for a relaxation of the parameters only in the case of a credit shortage or market disruption. Other stakeholders, from sectors such as natural gas, low-carbon fuels and electric vehicles as well as environmental non-governmental organizations, suggested maintaining or tightening the 10% limit.

The Department reviewed some of the parameters related to obligation deferral for the final Regulations. In particular, the period during which a deficit can be carried forward was increased to five years, and the interest rate was reduced to 5%. The final Regulations also allow for a primary supplier to take on a new deficit even if the primary supplier has not yet fully satisfied a deficit from a previous year, as long as the 10% obligation deferral limit is not exceeded. These changes will provide increased flexibility to regulated parties in case of temporary or short-term credit shortage without affecting total emission reductions achieved by the Regulations.

Cross-class trading

Several stakeholders, including provinces, primary suppliers, stakeholders from the gaseous and solid low-carbon fuel sectors and EITEs, asked to remove or increase the 10% limit on the use of gaseous and solid credits for annual compliance. Other stakeholders, including ENGOs and low-CI fuel producers and stakeholders from the electric vehicle and advanced vehicles sectors, recommended that the 10% limit be maintained or decreased.

The Regulations maintain the 10% limit on the use of gaseous credits for annual compliance. This is to provide flexibility to primary suppliers while remaining consistent with the scope of the Regulations, which target liquid transportation fuels. The 10% limit will incent the production of low-CI gaseous fuels such as hydrogen and renewable natural gas that could, in turn, be used in transportation. As there are no longer credit creation opportunities for solid fuels under the Regulations, the 10% limit only applies to gaseous credits.

Backstop for minimum credits from Compliance Categories 2 and 3

A group of stakeholders, mostly low CI fuels stakeholders, environmental non-governmental organizations, and EV charging stakeholders proposed a backstop provision that would guarantee a minimum of credits from Compliance Categories 2 and 3. It was noted by the stakeholders that the backstop would move Canada further away from the use of fossil fuels in transportation and towards using more low CI fuels and zero-emission vehicles.

The Regulations do not require a minimum number of credits from Compliance Categories 2 and 3. The Regulations take a technology neutral approach to reducing the CI of fuels by incentivizing investments across all three compliance categories. Credits from all compliance categories, including supplying low CI fuels and supplying fuel or energy to advanced vehicle technologies, will be needed in order for regulated parties to meet their reduction requirements.

Regional and consumer implications

Several stakeholders, including provinces, primary suppliers and ENGOs, expressed that the proposed Regulations caused a disproportionate impact on Atlantic Canada given the large proportion of consumers that rely on heating oil in the region. A number of suggestions were made to mitigate this impact, including exempting fuels that are used in stationary applications (e.g. heating oil, heavy fuel oil); providing funding to help the transition off heating oil; adding credit creation opportunities for end-use fuel switching in stationary applications; and, delaying the coming into force of the Regulations in Atlantic Canada. An exemption from the Regulations was also suggested for Newfoundland and Labrador to reflect the higher compliance cost as well as logistical and technical feasibility concerns specific to the province.

The Department removed the CI reduction requirements on heavy fuel oil, light fuel oil and kerosene, and added an exclusion for gasoline or diesel fuel used for space heating. The Department also maintained the exclusion for gasoline and diesel produced in and used at a primary supplier’s production facility for stationary applications. The Department also delayed the coming into force of the CI reduction requirements to July 1, 2023, for all regulated parties. For Newfoundland and Labrador, the Department did not provide additional exemptions to what was already provided in the proposed Regulations, but maintained the proposed exemption for Newfoundland and Labrador of the requirement for at least 5% of the volume of gasoline produced or imported to be displaced by an equivalent volume of gasoline replacement and for at least 2% of the volume of diesel produced or imported to be displaced by an equivalent volume of a diesel replacement. Fuels produced in or imported into Newfoundland and Labrador, and used in Newfoundland and Labrador, will still be subject to the CI reduction requirements. The Department also maintained the exclusion for fuels used in remote communities.

Impacts on industry

A number of comments were received regarding the potential impact of the proposed Regulations on industrial sectors, in particular EITEs. Many stakeholders acknowledged that the cancellation of the Department’s planned regulations for gaseous and solid fuels alleviated their concerns regarding the impact of the Regulations on industrial sectors. However, some industrial sectors that operate in remote locations with limited access to low-carbon energy options and that rely heavily on liquid fossil fuels asked for additional flexibilities to mitigate the impacts of the Regulations.

Removing the reduction requirements on heavy fuel oil and light fuel oil, which are used by industrial sectors, as well as allowing an exclusion for fuel used for remote power generation, will further reduce the impacts on industrial sectors. This is additional to flexibilities that are already built into the Regulations, such as unlimited banking of credits, which help minimize costs.

Administrative burden: Reporting, record keeping and quality assurance

A number of comments were received requesting: more time for registration and components of reporting, streamlining of the process for verification, validation and reporting via the Clean Fuel Regulations Credit and Tracking (CFR-CATS) system where possible, reducing administrative burden associated with record keeping and land use and biodiversity criteria, and flexibility at the outset of the final Regulations, to allow participants time to learn the Regulations and adapt to the CATS system.

In response to these comments, the several changes were made to the final Regulations. Primary suppliers must register within 90 days of the Regulations being registered, rather than within 10 days as set out in the proposed Regulations. The deadlines for reports after the end of a compliance period or credit creation period have been extended for most reports, including the quarterly credit creation report (an additional 60 days provided) and the annual credit creation report (an additional 30 days provided). The Department is also providing additional flexibility to allow early credit creation for Compliance Category 2 and 3 credits to be eligible as of the date the Regulations are registered, so long as the participant registered in CATS within 60 days of registration. Compliance credits for CO₂e emission-reduction projects under Compliance Category 1 will be eligible as of the date the project is recognized by the Department.

With respect to LUB criteria, declarations have changed from a per batch basis to a maximum of an annual basis, in order to allow streamlining with current buyer and seller contract periods. Foreign suppliers are no longer required to send their material balancing reports or documents to an importer, and can instead retain these on site. Registered creators and foreign suppliers will both complete the Material Balance report annually instead of quarterly.

With respect to verification and validation requirements in the Regulations, validation requirements have been removed from the final Regulations. As such, applications for CO₂e emission-reduction projects under Compliance Category 1 as well as CI applications with less than 3 consecutive months of input data will not require 3rd party validation. Additionally, with respect to verification, CI applications will be required to be verified as of June 30, 2024. This will provide time for participants and verification bodies to get familiarized with the Fuel LCA Model. The quantitative materiality thresholds applied during the verification of regulatory reports and applications will be aligned with other existing regulatory frameworks, such as the Output-Based Pricing System Regulations. Finally, submission deadlines for verification reports and corresponding regulatory applications or reports have been aligned; the final Regulations will require each verification report to be submitted together with the report or application to which it relates.

Fuel Life Cycle Analysis Model

The proposed Regulations were accompanied by the publication of the Fuel LCA Model methodology report, inviting stakeholders to comment on model design. The main comments received on the model include changing the allocation approach, including customizable feedstock and processes, considering carbon debt, including more fuel pathways and including carbon capture and storage.

TWG members had the opportunity to review the methodological approach and provide comments. Comments from stakeholders covered a broad range of topics, including requesting more options to customize feedstocks and processes, changing the allocation approaches, requesting for avoided emissions in multiple situations, comments on the treatment of biogenic carbon and including more fuel pathways. A common request amongst stakeholders was to make the Fuel LCA Model available as early as possible so that they could become familiar with it and inform investment decisions. These comments were considered when updating the methodology.

After the publication of the proposed Regulations in CG-I, the Department continued developing the model and made improvements based on internal analysis, testing of the model, expert review, external contracts and CG-I comments. The Department pre-published the Fuel LCA Model in December 2021 (see next section) as requested by several stakeholders in order to provide potential users the time needed to become familiar with the model prior to its formal publication and to provide information that can be used to inform potential business decisions.

Cost-benefit analysis

A large number of comments were received from all stakeholder categories on the cost-benefit analysis. The comments received on the CG-I publication generally focused on four categories. First, all stakeholders emphasized the need to update the analysis to account for the latest economic and emission projections, and new federal policy announcements such as the increase in the carbon pollution price. Second, many stakeholders requested clarification of the modelling results, particularly those regarding marginal abatement costs. Third, there were several requests to provide provincial and territorial cost-benefit analyses. Fourth, there were some questions about the break-even analysis methodology, which was used to value GHG reductions.

For the publication of the final Regulations, the Department updated the cost-benefit analysis based on comments received on the CG-I publication and to reflect the 2021 Reference Case, which takes into account the proposed carbon pollution price trajectory (to $170/tonne in 2030), as well as key interaction effects of the strengthened climate plan, such as zero-emission vehicles (ZEV) sales targets. As well, the analysis now includes a table (14) that summarizes costs per tonne per credit in order to provide a clear summary of marginal abatement costs. Since the benefits of GHG reductions are global in nature, regional cost-benefit analyses are not provided. However, the analysis includes an updated assessment of the potential regional cost impacts of the Regulations (Table 24).

Following the publication of the proposed Regulations, an expert review of the break-even analysis approach and social cost of carbon estimates was used to evaluate the results of the cost-benefit analysis. The reviewers concluded that the approach taken was reasonable and that the social cost of carbon estimates used accurately reflect the range of plausible values found in the scientific literature. Given this, the same break-even analysis approach was used for the publication of the final Regulations, and additional background information regarding the social cost of carbon was incorporated, as per the recommendation of the reviewers.

Additional consultations after the publication of the proposed Regulations in Canada Gazette, Part I

Fall 2021 consultations

In November 2021, the Department shared an update with stakeholders on the development of the quantification methods, LUB criteria, pre-publication of the Fuel LCA Model, and the timeline for the publication of final Regulations. Following this, the Department held bilateral meetings with each of the provinces and territories over fall 2021 and winter 2022. These meetings were held to provide an update to provinces and territories on the LUB criteria and to discuss legislative recognition. A comment period for the LUB criteria was open until December 31, 2021.

Comments received from provinces and territories, as well as domestic and international industry on the LUB criteria were generally concerned with legislative recognition in both Canada and the U.S.

The Department made additional wording changes to clarify and simplify the LUB criteria.

Spring 2022 consultations

In March 2022, the Department consulted with stakeholders through the MSCC. These consultations were to update stakeholders on the proposal to increase the stringency of the Regulations, as well as to change the coming into force date of the annual reduction requirements. The annual reduction requirement in 2030 was proposed to increase to 14 gCO₂e/MJ. The coming into force of the annual reduction requirements was proposed to be delayed until July 1, 2023, with reduction requirements starting in that year at 3.5 gCO₂e/MJ, increasing annually by 1.5 gCO₂e/MJ. This would allow for approximately one year of early credit creation between the registration of the Regulations and July 1, 2023. Two addendums were sent to the World Trade Organization, on March 18, 2022, and March 28, 2022, to notify Canada’s trading partners of these proposed changes. A comment period was open until April 8, 2022.

Primary suppliers were generally in favour of the proposed timing for one year of early credit creation. However, concern was expressed about the increase in the annual reduction requirements due to uncertainty in the credit market. Credit creators, including low CI fuel producers, supported the increase in stringency; however, some proposed an even greater target than 14 gCO₂e/MJ.

Fuel LCA Model

Stakeholder Technical Advisory Committee

The Stakeholder Technical Advisory Committee (STAC) was launched in fall 2021 with a first meeting in March 2022. The STAC includes representatives from the following sectors (industry or associations): fossil fuel, low-carbon fuel, electricity, agriculture, forestry and hydrogen. It also includes representatives from environmental non-governmental organizations and academia or LCA independent experts. All members of the STAC have expertise in life cycle assessment, GHG quantification or GHG credits trading schemes. The purpose of the STAC is to advise ECCC on the ongoing development and maintenance activities to the Fuel Life Cycle Assessment (LCA) Model.

Prepublication of Fuel LCA Model

The Fuel LCA Model was prepublished on December 20, 2021. The prepublication package included the Fuel LCA Model, the Fuel LCA Model methodology report, and the Fuel LCA Model user manual. CFR Specifications for the Fuel LCA Model Carbon Intensity Calculations and a CFR Data Workbook were also included in the pre-publication package.

In January 2022, the Department held an information session and organized training sessions in February 2022.

Following the pre-publication of the Fuel LCA Model, changes were made to the published final version to fix bugs, make changes on the Soil Organic Carbon approach and integrate new elements.

Modern treaty obligations and Indigenous engagement and consultation

As required by the Cabinet Directive on the Federal Approach to Modern Treaty Implementation, an assessment of modern treaty implications was conducted on the proposal. The assessment did not identify any modern treaty implications or obligations since the proposal is outside of the subject matter scope covered in modern treaties.

Indigenous governments and groups were invited to participate in the extensive engagement process held with stakeholders throughout the development of the Regulations. Overall, 15 Indigenous organizations were invited to participate in the MSCC meetings. During one of these meetings, a general question regarding credit creation opportunities was posed and answered. Additionally, one Indigenous organization joined the TWG and has had bilateral conversations with the Department on the Regulations including on the Fuel LCA Model. The Department informed Indigenous groups of the opportunity to comment further upon publication of the proposed Regulations in the Canada Gazette, Part I. One Indigenous organization provided comments as part of that formal comment period. Since that time, 15 Indigenous organizations were invited to participate in engagement sessions in November 2021 and March 2022 to provide an update on the development of the proposed Regulations. No comments or questions were received as a result of those sessions.

Instrument choice

Development of the PCF involved the identification of a wide range of policy options for reducing GHG emissions, including the Regulations to reduce the CI of fuels. The process for evaluating the instrument choice focused on options for how to reduce the CI of fuels. Consideration was given to four options: increase the stringency of the renewable fuels requirements under the federal RFR, increase the stringency of carbon pricing, propose a CI standard covering liquid, gaseous and solid fuels concurrently, or implement a phased CI standard approach first beginning with a CI standard for liquid fuels and with CI standards for gaseous and solid fuels to follow.

The Department considered increasing the volumetric requirements under the RFR and adding CI reduction requirements for the renewable fuels. This approach was rejected on the basis that it was less flexible for regulated parties as it will not allow for low CI fuels that are not renewable (e.g. fuels produced from direct air capture and carbon recycling), nor other CI reduction methods (such as GHG emission reduction projects along the lifecycle of fuels, supplying fuel or energy to advanced vehicle technologies).

As announced in the December 2020 Strengthened Climate Plan, the Regulations take a lifecycle CI approach, meaning they take into account the emissions associated with all stages of fuel production and use – from extraction through processing, distribution, and end use. The Regulations complement the price on carbon pollution. While carbon pricing creates a broad incentive across the whole economy to use less energy and improve efficiency, the Regulations target transformative change in how fuels are produced and used in Canada. This is crucial for long-term decarbonization and to put Canada on the path to net-zero emissions by 2050.

In the context of the continued increase to the carbon price, the scope of the Regulations has been narrowed to cover only liquid fossil fuels, like gasoline and diesel, which are mainly used in the transportation sector. This is a progression in the design of the Regulations from their initial scope in 2016, when it was proposed that the new measure would cover liquid, gaseous and solid fuels. The Regulations, covering only liquid fossil fuels, will remain an integral policy in Canada’s strengthened climate plan, and will contribute to the Government’s goal of meeting its current 2030 target.

Regulatory analysis

Under the Regulations, primary suppliers (the regulated entities) will have an annual CI reduction requirement for the amount of gasoline and diesel supplied domestically. The annual CI reduction requirement will become more stringent from 2023 to 2030, starting at 3.5 grams of carbon dioxide equivalent per megajoule (gCO₂e/MJ) in 2023 and reaching 14 gCO₂e/MJ in 2030 (see Table 1), representing approximately 15% in CI reduction from 2016 levels. A primary supplier’s annual reduction requirement is expressed in lifecycle tonnes of carbon dioxide equivalent (tCO₂e) and is calculated on a company-wide basis, summing up the reduction requirements per liquid fossil fuel type for each production facility and for their total imports.

There are 30 companies that refine, upgrade or import liquid fossil fuels that are regulated parties under the Regulations. Of these, 14 companies own refineries and upgraders, 8 of which who also import. Roughly 95% of oil upgrading capacity is located in Alberta and the remaining 5% is located in Saskatchewan. About 34% of oil refining capacity is located in British Columbia, Alberta, Saskatchewan and Manitoba, while 43% is in Ontario and Quebec and about 23% in the Atlantic Provinces.^{footnote 24}

The Regulations establish a credit market, where each credit represents a lifecycle emission reduction of one tonne of CO₂e. For each compliance period, a primary supplier demonstrates compliance by retiring the required amount of credits. Parties that are not primary suppliers are able to participate in the credit market as credit creators (non-mandatory participants). Credit creators include low-carbon fuel producers/importers (e.g. biofuel producers), electric vehicle charging site hosts, network operators, fuelling station owners or operators, as well as parties upstream or downstream of a refinery such as an oil sands operator.

The Regulations have the following three main categories of credit-creating actions: (1) actions that reduce the CI of the fossil fuel throughout its lifecycle; (2) supplying low-carbon fuels for use in Canada; and (3) supplying fuel or energy to advanced vehicle technology. A liquid class credit reference CI value is used to calculate the amount of compliance credits created for low-carbon fuels and some fuel or energy used in advanced vehicle technologies.^{footnote 25} These are shown in Table 1 between 2022 and 2030.

Table 1: Annual liquid lifecycle CI reduction requirements for primary suppliers
	2022	2023	2024	2025	2026	2027	2028	2029	2030
CI reduction requirement (gCO₂e/MJ)	n/a	3.5	5.0	6.5	8.0	9.5	11.0	12.5	14.0
Liquid class credit reference CI value (gCO₂e/MJ)	89.2	89.2	87.9	86.6	85.3	84.0	82.7	81.4	80.1

Note: Liquid lifecycle CI reduction requirement for 2023 starts July 1, 2023. From 2024 onwards, the requirement starts January 1.

Primary suppliers can comply via the three main categories of credit creation. However, they may also comply by acquiring compliance credits from other credit creators, or by contributing to a compliance fund mechanism for up to 10% of their annual reduction requirement. The credit price under the fund is set in the Regulations at $350 in 2022 per compliance credit (Consumer Price Index (CPI) adjusted). Gaseous compliance credits may also be used for up to 10% of the annual reduction requirement. A diagram of how the credit market works is shown in Table 2 below (for illustrative purposes only).

Table 2: Illustrative diagram of credit market actions by participant
Participant	Action	Credit Calculation	Result
Primary suppliers (Refinery / upgrader / importer)	Supply liquid fossil fuels (e.g. gasoline)	Annual CI reduction requirement (gCO₂e/MJ) × Fossil fuel supplied (MJ) ÷ 1 000 000 (g/t)	Emissions (tCO₂e) = Compliance deficits
Primary suppliers / companies upstream or downstream of a refinery	Reduce the CI of fossil fuel throughout lifecycle (e.g. process improvements)	Credit calculation is project-type specific based on GHG emissions reduced	Avoided emissions (tCO₂e) = Compliance credits
Low-carbon fuel suppliers (Producer / importer)	Supply low CI for use in Canada (e.g. ethanol)	[Liquid class credit reference carbon intensity − Specific lifecycle CI value] (gCO₂e/MJ) × Energy supplied (MJ) ÷ 1 000 000 (g/t)	Avoided emissions (tCO₂e) = Compliance credits
Charging site hosts / network operators / fueling station operators or owners / low-carbon fuel suppliers	Supplying fuel or energy to advanced vehicle technologies (e.g. electric vehicles, natural gas vehicles, hydrogen fuel cell vehicles)	[Energy Efficiency Ratio × Liquid class credit reference CI − Specific lifecycle CI value] (gCO₂e/MJ) × Energy supplied (MJ) ÷ 1,000,000 (g/t)	Avoided emissions (tCO₂e) = Compliance credits

Benefits and costs

It is estimated that credit creation from actions that are expected to occur in the baseline, such as credits from low-carbon fuels supplied for federal and provincial blending mandates, plus banked credits from previous years, will be sufficient to fulfill the regulatory requirements for the first few years that the annual reduction requirements are in force (2023 and 2024), as shown in Figure 1. By 2025, credits from incremental actions will be required, and it is estimated that 2025 is the last year in which banked credits will be used and the first year in which the fund would be accessed. In 2026, it is estimated that credits from emerging technologies will be required to fulfill the annual CI reduction requirement. The fund and emerging technology pathways represent the highest cost compliance options that are available when cheaper options have all been exhausted. Emerging technologies make up the difference between the amount of credits required and credits from known pathways. For this analysis, actions taken using emerging technologies are assumed to cost the same as the fund. The Regulations reach full stringency in 2030 and required credits created reach a peak of 34.3 million. Total credits required decrease slightly from 2031 to 2040. This is because the demand for fossil fuel is expected to decline as zero-emissions vehicles (ZEVs) make up a growing share of vehicles on the road.

Figure 1: Estimated credits required, created and banked, 2022–2040 (millions)

Figure 1: Estimated credits required, created and banked, 2022–2040 (millions)

The most significant costs will be incurred in 2024, as firms start to draw down their bank of credits and have to make significant capital investments in order to comply with increasingly more stringent CI reduction requirements. Incremental GHG emission reductions are expected to begin in 2025 as incremental projects come online. In 2030, when the Regulations reach full stringency, there will be incremental GHG emission reductions of about 18.0 megatonnes of carbon dioxide equivalent (Mt CO2e). After 2030, it is estimated that incremental GHG emission reductions will decline to about 9.5 Mt in 2040. The compliance costs for the Regulations are also estimated to decline after 2030. This is because credits from actions expected to occur in the baseline rise over time as the CI requirement stays constant at 14 gCO2e/MJ, resulting in non-incremental baseline credits crowding out credits from incremental actions. The CI reduction requirements after 2030 will be subject to a review of the Regulations and potential future amendments. A large increasing source of baseline credits are expected to come from compliance category 3, as EVs are expected to comprise a larger share of on-road vehicle make-up in response to the light-duty vehicle (LDV) ZEV sales targets.

Figure 2: Incremental GHG emission reductions by year

Figure 2: Incremental GHG emission reductions by year

Figure 3: Present value net costs by year

Figure 3: Present value net costs by year

Between 2022 and 2040, the incremental cumulative GHG (i.e. CO₂) emission reductions attributable to the Regulations are estimated to range from 151 to 267 Mt, with a central estimate of approximately 204 Mt. To achieve these GHG emission reductions, it is estimated that the Regulations could result in societal costs that range from $22.6 to $46.0 billion, with a central estimate of $30.7 billion. The GHG emission reductions will be achieved at an estimated societal net cost per tonne between approximately $111 and $186, with a central estimate of $151.

The social cost of carbon (SCC) is a monetary measure of the net global damage from climate change that results from an additional metric tonne of CO₂ emissions for a given year. When measuring the benefits associated with reductions in CO₂ (i.e. GHG) emissions, all federal government departments must use the SCC estimates published by the Department. The Department’s central SCC estimate for the year 2020 is currently $52/tCO₂, adjusted for inflation. However, recent literature suggests the SCC values currently used by the federal government are out of date and are underestimated. While the Government’s Strengthened Climate Plan, A Healthy Environment and a Healthy Economy, includes a commitment for the federal government to update the SCC estimates in use, revised estimates are currently not available.

Given the uncertainty associated with what an updated SCC might be, a break-even analysis was conducted that compares the net societal cost per tonne of the Regulations to the Departmental value of the SCC published in 2016, and to more recently published estimates of the SCC value found in the literature. A Monte Carlo analysis was also conducted to determine the probability of the benefits of the Regulations exceeding the costs, given the range of SCC estimates and net societal cost per tonne estimates. Overall, based on a Monte Carlo simulation, there is a high probability (75% chance) that updated SCC estimates will exceed the estimated societal cost per tonne estimates of the Regulations. As such, the Department concludes that it is plausible that the monetized benefits of the Regulations will exceed its costs.

The Regulations will increase production costs for primary suppliers, which will increase prices for households and industrial users. Credit creation will also generate revenue for low-carbon energy suppliers, which will make low-carbon fuels such as renewable diesel and energy sources such as electricity relatively less expensive. This will lead to decreased end-use demand for fossil fuels and increased end-use demand for lower-carbon fuels and energy sources, thereby reducing national GHG emissions.

To evaluate the direct impact of the Regulations as well as the effect of relative price changes on Canadian economic activity and GHG emissions, a macroeconomic analysis was completed. When price effects are taken into account, it is estimated that the Regulations will result in up to 26.6 Mt of GHG emission reductions, with a decrease in GDP of up to 0.3% in 2030, using an upper bound fuel price increase scenario where all credits are sold at the marginal cost per credit.

The costs of the Regulations will not be evenly distributed across society. Households and industrial sectors that consume more gasoline and diesel are expected to incur a higher impact. Given the wide variability among regional and sectoral impacts, the distributional impacts are presented in the distributional analysis of regulatory impacts section.

Analytical framework

TBS guidance: The impacts of the Regulations have been assessed in accordance with the Treasury Board of Canada Secretariat (TBS) Canadian Cost-Benefit Analysis Guide.^{footnote 26} Impacts have been identified, quantified and monetized where possible, and compared incrementally to a non-regulatory scenario.

Key impacts: The logic model in Figure 4 illustrates the incremental impacts of the Regulations that are quantified and monetized in this analysis. Compliance actions under the Regulations will result in incremental domestic GHG emission reductions, net capital and operating costs for industry, as well as administrative costs for both industry and government. Compliance costs are also expected to decrease the demand for energy and therefore on economic output. This will further reduce GHG emissions. Other impacts are assessed qualitatively.

Figure 4: Logic model for the analysis of the Regulations
Compliance actions taken under the Regulations	→	Reduction in domestic GHG emissions	→	Reduction in climate change damages	→	Social benefits
Compliance actions taken under the Regulations	→	Net compliance costs	→	Reduction in economic output	→	Social costs

Baseline scenario: The baseline scenario assumes a status quo in which the Regulations are not implemented. The baseline scenario is based on 2021 GHG emission projections Reference Case, which itself uses the 2021 GHG emissions inventory as an input. Therefore, the baseline scenario accounts for the projected impacts associated with the COVID-19 pandemic. Independent industry and consumer actions to reduce GHG emissions have also been considered as part of the baseline scenario, to the extent possible (e.g. trends in electric vehicle uptake). The assumptions in the baseline scenario include the federal carbon pollution pricing backstop system increasing to $170/tonne by 2030 (the federal backstop system), provincial carbon pricing policies, the future impact of relevant policies and measures taken or announced in detail by the federal, provincial and territorial governments as of November 2021, as well as incorporating the target of 100% sales of new light duty vehicles being ZEV in 2035.^{footnote 27,}^{footnote 28}

Regulatory scenario: The analysis compares the expected impacts of the Regulations (the regulatory scenario) to a scenario that assumes the Regulations are not implemented (the baseline scenario). Societal costs are directly incurred as a result of the creation of compliance credits, not as a result of acquiring compliance credits in trade. Therefore, compliance credit purchases are a transfer payment between parties since a payment from one party to another is not considered a cost to society as a whole. Moreover, it is expected that some credit-creating activities taken under the Regulations will be attributable (or partially attributable) to other federal and provincial policies or industry action that would have occurred in the absence of the Regulations. Given this, it is expected that not all of these activities, and thus not all the costs and emission reductions associated with these activities, will be attributable to the Regulations. All benefits and costs presented will be incremental to the baseline scenario, unless otherwise specified.

Time frame of analysis: The time frame considered for this analysis is 2022 to 2040. The Regulations are assumed registered on July 1, 2022, and the CI reduction requirements for gasoline and diesel come into force on July 1, 2023, twelve months after the registration of the Regulations. The annual CI reduction requirement will become more stringent between 2023 and 2030, starting at 3.5 gCO₂e/MJ in 2023, reaching 14 gCO₂e/MJ by 2030. A 2022 to 2040 time frame was considered sufficient for estimating most of the impacts, since GHG emission reductions are not expected to occur until 2025 and most of the costs are not expected to occur until 2024. Reductions and costs are also expected to decrease annually beyond 2030 as the annual CI reduction requirement stays constant at 14 gCO₂e/MJ and non-incremental credits from actions expected to occur in the baseline rise over time, crowding out credits from incremental actions. The CI reduction requirements after 2030 will be subject to a review of the Regulations and potential future amendments. Finally, forecasts of oil and natural gas prices and production are taken from the Canada Energy Regulator, which are available up to 2040.^{footnote 29}

Monetary costs: All monetary results are shown in 2021 Canadian dollars, inflating non-2021 values (using GDP Deflator data), and converting non-Canadian prices (2021 exchange rates).^{footnote 30} When shown as present values, future year impacts have been discounted at 3% per year as per TBS guidance, and shown as present value in 2022.

Lifecycle analysis versus national inventory accounting

The Regulations require CI reductions along the lifecycle of fuels. A lifecycle approach considers the GHG emissions involved in multiple stages of the fuel’s production process, from feedstock extraction or cultivation to fuel combustion. The lifecycle CI of fuels includes GHG emissions that occur over multiple years and in multiple sectors such as the emissions associated with the use of electricity inputs, fuel inputs, material and chemical inputs, transportation and land use change. This is fundamentally different from a national GHG inventory approach that quantifies GHG emissions from different industrial or economic sectors on an annual basis.

A national inventory approach accounts for emissions from imported finished fuels; however, it only accounts for the portion of those lifecycle emissions occurring within Canada’s boundaries. This includes mainly the emissions from transporting, refining and processing the fuel, as well as its combustion in Canada. Lifecycle analysis (LCA) considers emissions from imported fuels that occur in other jurisdictions where these fuels are produced. National inventory accounting is a standardized approach used by participating countries in the United Nations Framework Convention on Climate Change (UNFCCC). Using it enables comparisons between countries and provides a framework for the global accounting of emissions. The LCA approach is not concerned with national boundaries and seeks to quantify all emissions from the extraction or cultivation of the feedstock to the combustion of fuels. Compliance credits under compliance categories 2 and 3 will be created under the Regulations using the LCA approach, based on LCA CI values. For Compliance Category 1, the number of credits created will be determined in accordance with a quantification method (QM) that is consistent with International Standard ISO 14064-2 entitled Specification with Guidance at the Project Level for Quantification, Monitoring and Reporting of Greenhouse Gas Emission Reductions or Removal Enhancements and published by the International Organization for Standardization.

The Department used the national inventory accounting approach in order to estimate incremental GHG emissions reductions, which is consistent with the Departmental reference case and international reporting requirements. Canada’s GHG inventory is developed, compiled, and reported annually by the Department, and is prepared in accordance with the UNFCCC reporting guidelines. Canada’s emissions projections in the departmental reference case are based on end-use combustion emission intensities and include only domestic emissions. All emissions and removals attributed to direct land use change are excluded from the national emissions total.^{footnote 31}

Pathway modelling and analysis

The Regulations give primary suppliers flexibility in terms of how to comply. As such, it is not possible to forecast and monetize all possible compliance pathways that may exist now and in the future. To assess the impacts of the Regulations, a representative set of pathways for creating compliance credits were identified for each of the three categories of compliance credit-creation (actions that reduce the CI of the fossil fuel throughout its lifecycle; supplying low-carbon fuels; and supplying fuel or energy to advanced vehicle technologies).

To the extent possible, the representative credit-creating pathways used for analysis have considered what has occurred in other jurisdictions with similar policies (such as California’s Low Carbon Fuel Standard), as well as pathways that are technologically ready or commercially available today. The analysis attempts to identify the technical or economic barriers to achieving reductions under each credit-creating pathway in order to establish an upper bound estimate on the number of compliance credits that could be created for each pathway by 2030.

Some of the credits that will be created under the Regulations will not be directly attributable to the Regulations. These credits arising from baseline actions will count towards compliance but are not considered incremental in the analysis. Therefore, each potential pathway has been assessed in terms of compliance credits created, and incremental emission reductions and compliance costs through a partial equilibrium (or static) analysis. This analysis assumes that the demand for energy remains constant, and does not include energy price impacts on GDP and GHG emissions.

It is assumed that firms will choose the least-cost available credit-creating pathways in order to comply with the Regulations and pathways are ranked in the order of estimated cost per credit. Low-cost pathways may be chosen in part because of other policies (e.g. existing fuel blending requirements), or existing trends (e.g. electric vehicle uptake), or because of industry innovations that may develop in the absence of the Regulations (e.g. carbon capture and storage). As such, emission reductions and costs from these pathways will be considered as part of the baseline scenario and will not be attributed to the Regulations (non-incremental). Therefore, estimates of total pathway compliance credits may under or overestimate the incremental impacts of the Regulations. The analysis considers both estimates of compliance credits created and the likelihood of the attribution of their emission reductions and costs to the Regulations. The representative compliance pathways and their likelihood of attribution to the Regulations are presented in Table 3.

Table 3: Representative pathways and attribution to the Regulations
Representative Compliance Pathway	Attribution
Emerging technologies (e.g. co-processing)	Incremental
Compliance fund	Not quantified
Blending ethanol in the gasoline pool	Incremental
Blending biodiesel/HDRD in the diesel and light fuel oil pools	Incremental
Carbon capture and storage (CCS)	Incremental
Existing projects started after July 2017 and announced before the end of 2020	Non-incremental
Supplying electricity and natural gas/propane to advanced vehicle technologies	Non-incremental
Low-carbon fuels from existing blending mandates	Non-incremental

Impacts from compliance categories

The Regulations have three main categories of credit-creating actions: (1) actions that reduce the CI of the fossil fuel throughout its lifecycle; (2) supplying low-carbon fuels; and (3) supplying fuel or energy to advanced vehicle technologies. The credit-creating actions have been assessed using representative pathways. Primary suppliers will also be able to comply by contributing to a compliance fund mechanism for up to 10% of their annual reduction requirement. The credit price under the fund is set in the Regulations at $350 (in 2022 nominal dollars) per compliance credit (CPI adjusted). The estimated impacts of these categories of credit-creating actions and the fund are described below.

Compliance Category 1: Actions that reduce the carbon intensity of the fossil fuel throughout its lifecycle

Parties may be able to take actions along the lifecycle of fossil fuels that reduce the CI of the fuel. These actions could be taken by primary suppliers (e.g. refinery/upgrader) and by credit creators upstream or downstream of a primary supplier (e.g. crude/oil sands producer).

For Compliance Category 1, the number of credits created will be determined in accordance with a quantification method (QM), which specifies the eligibility criteria for the project as well as the approach for quantification. The Department will maintain a list of eligible quantification methods outside of the Regulations. Projects will have to generate emission reductions that are real and incremental to a defined baseline (i.e. additional) to be able to create compliance credits. For all quantification methods other than the generic quantification method, this additionality will be assessed during the development of the quantification method. For the generic quantification method, additionality will be assessed at the project level. All quantification methods will be reviewed periodically for additionality, and maintained, modified or withdrawn accordingly.

The estimated compliance credits, costs, and reductions for representative credit-creating pathways in this category are presented below. The representative pathways for this category of credits are carbon capture and storage and enhanced oil recovery. Other project types are not included in the central analysis, but are still eligible for creating credits under other quantification methods. For example, refinery process improvements and methane conservation pathways are not included in the central case analysis, as other policies are expected to incentivize these actions, but are still eligible for creating credits under the generic quantification method.

Carbon capture and storage and enhanced oil recovery

Carbon capture and storage (CCS) captures CO₂ emissions from industrial facilities before they are released into the atmosphere. Once captured, the CO₂ is compressed and transported to a storage site, where it is injected underground in geological formations. The CO₂ captured can also be used for other purposes, often referred to as carbon capture, utilization and storage (CCUS). For example, CO₂ can be used as an additive to improve the integrity of products such as cement. A common subset of CCUS is enhanced oil recovery (EOR), which is a process that injects CO₂ underground into mature oil fields to increase the amount of oil that can be recovered from an oil reservoir while storing CO₂ underground.

Two quantification methods have been developed under the Regulations for CCS and EOR projects. Credits can be created for CCS and EOR projects that capture CO₂ emissions from facilities that produce liquid fossil fuels or crude oil and hydrogen production facilities that supply hydrogen to these facilities. To mitigate credit liability, a percentage of credits will be held back to cover risks of potential future leaks. The Regulations will apply a 0.5% discount factor for CCS credits that will never be returned to the project proponent.

Credit-creation: It is expected that about 1.1 million credits per year will be created from CCS/EOR projects that started after July 1, 2017, but that were announced before the end of 2020. These actions will create early credits in the initial years following the registration of the Regulations.

There is a significant amount of uncertainty in the estimation of future CCS/EOR projects. CCS projects tend to have high capital costs that often vary by project. They are also dependent on the depth of storage, the storage site, and the method and materials required to capture and store carbon. According to the Global CCS Institute, the cost per tonne of CO₂ avoided in Canada could range from $40 to $260 depending on the sector. Costs of CCS can be reduced if there is opportunity for EOR; however, there also tends to be some technical uncertainty when implementing projects (e.g. issues with the amine solution at the Boundary Dam facility for the first few years of development).^{footnote 32}

It is assumed that 3 million credits per year from additional CCS projects could come online before 2030 as a result of the Regulations. This is based on a combination of project announcements, upward pressures on new CCS projects through policy measures including the Investment Tax Credit, and a review of 2017 data from the Greenhouse Gas Reporting Program on facilities located near potential storage sites in the Alberta Industrial Heartland.^{footnote 33} While there is potential to exceed this estimate, upfront costs and technical uncertainties could limit the development of new creditable CCS/EOR projects during the initial years of implementation of the Regulations. CCS is expected to experience improvements in cost and technical performance into the future. It is reasonable to expect that there will be some increased CCS/EOR capacity in the long-term as the Regulations ramp up in stringency and demand for credits increases.

It is estimated that incremental credits from CCS/EOR projects will start in 2025 since baseline and banked credits will no longer be sufficient to fulfill the annual CI reduction requirement. As such, it is estimated that these projects will create about 1.1 million credits in 2022, rising to 4.1 million in 2030, and are assumed to remain constant at 2030 levels between 2031 and 2040.

Attribution: Any CCS/EOR projects that started after July 2017 but that were announced before the proposed Regulations were published in December 2020 are not considered incremental as they are expected to be attributable to federal and provincial subsidy programs. Since CCS/EOR projects tend to have high, upfront capital cost barriers and technical uncertainty, CCS/EOR projects are unlikely to occur without regulatory and policy incentives. Credits from the Regulations are expected to provide enough of an incentive such that CCS/EOR projects announced after the publication of the proposed Regulations will be considered attributable to the Regulations.

Incremental impacts: Cumulative reductions between 2022 and 2040 are estimated at 48 Mt of CO₂. The estimated capital cost of CCS/EOR is about $1,250 million on average per Mt of annual CO₂ sequestered capacity. This estimate is based on data from large-scale CCS/EOR projects that have been completed in Canada and the U.S.^{footnote 34} These projects were the first few of their kind in the U.S. and Canada, and it is expected that future projects could have lower costs as the technology matures.^{footnote 32} However, declining technology costs have not been modelled given that there is uncertainty as to how much technology costs may decline over time. It is assumed that the operating costs for a given year are 4% of the capital costs (about $50 million annually per Mt of CO₂ sequestered).^{footnote 35} There could be substantial cost savings from projects that use EOR. However, due to a lack of data on the potential for oil recovery from such projects, the cost savings have not been modelled. Total capital costs for this pathway are estimated at $3,785 million and total operating costs are estimated at $1,902 million over the time frame of analysis. Overall, it is estimated that this pathway will result in a total compliance cost to industry of about $5,686 million between 2022 and 2040.

Higher estimate of CCS from other policy tools

The 2030 Emissions Reduction Plan (ERP) published on March 29, 2022, describes the many actions that are already driving significant reductions, as well as the new measures that will ensure that we reduce emissions across the entire economy to reach our emissions reduction target of 40 to 45% below 2005 levels by 2030 and put us on a path to achieve net-zero emissions by 2050.

The Government of Canada has announced or implemented several measures to boost the implementation of CCS. These measures include the ITC for Carbon Capture, Utilization, and Storage, the increased price of carbon pollution and the cap on oil and gas emissions. The ITC is a proposed investment tax credit for the capital invested in CCS projects with the goal of reducing emissions by at least 15 Mt of CO₂ annually. The Government intends to make the investment tax credit available in 2022.

Given the Regulations and other policies to encourage a strong adoption of the technology, it is expected that there will be more than 3 Mt of credits created from CCS projects by 2030. Credits created through the CCS pathway may likely exceed the central case estimate. A 3 Mt estimate was applied in the central case due to several factors. The first is a narrower scope of eligible CCS projects under the Regulations. CCS projects that are eligible for credit creation under the Regulations are limited to projects that reduce the CI of liquid fossil fuels. CCS facilities that are under operation to reduce emissions from industrial production, such as cement, are not eligible to create credits for the Regulations. Second, CCS tied to a biofuel production facility has not been considered within this compliance category. It is expected that reductions due to a CCS process for a biofuel facility will lower the CI of the low-carbon fuel, allowing the same volume of fuel to create more credits. The central case assumes a constant renewable and low-carbon fuel CI for the analysis period, however, a sensitivity analysis scenario examining a lowering of the CI has been conducted. A different sensitivity analysis scenario examines if the uptake in creditable incremental CCS is double the central case, bringing the total to 6 million credits. Uncertainty of the overall CCS credits is addressed in the uncertainty of impact estimates section.

In addition, there will not be credit creation for emission reductions associated with exported fossil fuels, which represents a significant amount of crude oil production in Canada. For example, if a CCS projects is undertaken at in situ operation, and 90% of the crude is exported to the U.S., credits will only be awarded for 10% of captured and sequestered emissions.

Compliance Category 2: Supplying low-carbon-intensity fuels

Low-CI fuel producers and importers (the default credit creators) will create credits by supplying low-carbon fuels for use in Canada. Based on similar policies in other jurisdictions (e.g. British Columbia, California), the most-likely representative pathways under this category will be to increase the supply of the following low-CI fuels: ethanol in gasoline, biodiesel in diesel and light fuel oil (LFO), hydrogenation-derived renewable diesel (HDRD) in diesel and LFO.^{footnote 36,}^{footnote 37}

Technical and economic blending barriers

The United States Environmental Protection Agency (EPA) has registered ethanol blends of up to 15% (E15) as a fuel for use in model year 2001 and later for new cars, light-duty trucks, and medium-duty passenger vehicles. Therefore, it is expected that the future vehicle fleet in Canada could handle E15 by 2030 as a pathway under the Regulations.^{footnote 38}

However, to accommodate an ethanol blend above 10%, terminals would have to store fossil fuels with higher volumes of low-carbon fuel. It is expected that they will incur capital and operating costs to install or upgrade infrastructure (such as the installation of additional storage or shipping capacity). Additionally, retail and cardlock fuelling stations will have to provide blended fuel to end users. It is assumed that most fuelling stations are currently equipped to handle up to 10% ethanol. To blend up to E15, existing retail gas stations would need to either repurpose existing tanks and add a dispenser (low cost), or install a new tank and dispenser (high cost).

A number of terminals and retail fuel stations are independent from the regulated parties and, may be unable or unwilling to incur capital costs to accommodate the higher blends of ethanol. Furthermore, with a 100% sales target for ZEV LDV sales by 2035, it is expected that the demand for gasoline will significantly decrease. Capital expenditure in retail fuel stations may shift towards accommodating EV charging infrastructure over projects to increase fuel blending beyond existing operational constraints. As such, it may be more reasonable to expect ethanol blend of 10% in jurisdictions where there is no other blending mandate.

For biodiesel, the majority of North American engine manufacturers endorse up to a 5% biodiesel in diesel blend (B5). The Engine Manufacturers Association issued a technical statement indicating biodiesel use up to B5 should not cause engine or fuel systems problems.^{footnote 39} As biodiesel becomes more widely tested and used, manufacturers will be in a better position to support the use of higher blends. Warranty coverage of B20 and higher is offered by select manufacturers under specific conditions. However, similar to the use of regular diesel, some manufacturers may limit the scope of their warranties by stating that failures from the use of any fuel cannot be attributed to a factory defect. Therefore, the cost of repair under these circumstances (if any) would not be covered by certain warranties. As a result, it is expected that the future vehicle fleet in Canada could handle biodiesel blends of up to 5% by 2030.^{footnote 40}

HDRD is a drop-in fuel, with properties indistinguishable from those of petroleum diesel. It has been successfully tested up to a 50% blend at various climate conditions in existing diesel-fuelled engines.^{footnote 41} However, HDRD currently competes with biodiesel for feedstock and is more costly to produce than biodiesel and petroleum diesel.^{footnote 42} Domestic HDRD consumption in 2017 was 250 million litres. HDRD is not produced domestically and global production in 2017 of HDRD was only about 4 billion litres per year.^{footnote 43,}^{footnote 44} Given this, it may be more reasonable to expect HDRD blends closer to about 6% (or about 1.3 billion litres of additional HDRD) by 2030. This will require the construction of roughly three new HDRD facilities by 2030, either in Canada or globally.

Domestic production versus imports of low-carbon-intensity fuels

The Regulations are expected to provide market signals that will increase the demand for low-CI fuels in Canada. At the same time, Canada’s Clean Fuels Fund will support domestic production by investing $1.5 billion over five years to de-risk the capital investment required to build new or expand existing clean fuel production facilities in Canada. Additional volumes are expected to be met with a combination of increased domestic production and imports. The Regulations concerning credit creation do not differentiate between domestic and imported low-carbon fuels. The Regulations require the use of the Fuel LCA Model to calculate facility-specific CI values, and the same requirements apply to imported low-carbon fuels. Therefore, the lower the CI value a low-CI fuel has on a lifecycle basis, the more credits the low-CI fuel producer or importer will obtain. Existing producers and importers of low-CI fuel in Canada are expected to benefit from the demand created by the Regulations.

Between 2013 and 2017, domestic production of ethanol has been approximately 1.8 billion litres per year, while domestic consumption in the same period has been between 2.8 to 3.0 billion litres per year. The difference has been met by American ethanol imports.^{footnote 45} The United States has a projected surplus for ethanol in 2030, estimated at 6 billion litres.^{footnote 46} Midwestern states have enacted regulations to promote ethanol production as an indirect measure to support local farming.^{footnote 47} Currently, Brazil is the largest importer of ethanol from the United States, followed by Canada. Given these factors, it is possible that Canada could import additional volumes of ethanol needed (about 0.7 billion litres) to achieve E10 in jurisdictions where no higher blend rate is required.

Approximately 1 billion litres of additional biodiesel will be required to achieve a 5% blend rate in 2030. Domestic biodiesel demand in 2017 was approximately 550 million litres. Canada currently produces enough biodiesel domestically to meet this demand at about 600 million litres. However, Canadian producers exported 300 million litres to the United States in order to take advantage of tax incentives available there for low-carbon fuels. The remaining domestic demand for biodiesel was imported.^{footnote 43} Importing the required quantities is possible; however, if this pathway is taken, regulated parties may have to pay a higher price for biodiesel. Based on recent announcements, commercial HDRD projects in Canada are anticipated to begin production in the coming months and over the next few years. However, there is not yet certainty that these volumes of HDRD would stay in Canada. As such, it is assumed that additional volumes of HDRD will be imported in the near future.

Given the availability of imports and the capital cost barriers involved with a rapid scale up in domestic supply, the analysis assumes for simplicity that additional volumes of ethanol, biodiesel and HDRD supply will be met by imports. Nonetheless, it is reasonable to expect that there will be some increased domestic production in the long-term as the Regulations ramp up in stringency and demand for low-CI fuels increase. This will provide a stronger and more reliable signal to investors with regard to de-risking capital investments. In addition, if the CI value of domestically produced low-CI fuels are lower than imported low-CI fuels, this will provide an additional incentive for domestic production.

Credits created from supplying low-carbon-intensity fuels

Credits will be earned by low-carbon fuel producers and importers for the amount of low-carbon fuel supplied in Canada and will be issued using an LCA approach. The same volume of renewable fuel used to meet federal and provincial volumetric blending requirements and low-carbon fuel standards may be used to create credits under the Regulations.

The regulatory scenario assumes that by 2030, the ethanol content in gasoline increases to 10%, and biodiesel and HDRD content in diesel and LFO increases to 5% and 6% respectively on a volumetric basis, up from baseline levels. Credits are estimated by multiplying the amount of energy supplied under the regulatory scenario by the difference between the liquid class credit reference values (shown in Table 1 above) and the CI of the low-carbon fuel. For the purpose of this analysis, national average LCA CI values are used in the calculation of credits and are estimated at 49 gCO₂e/MJ for ethanol, 26 gCO₂e/MJ for biodiesel and 29 gCO₂e/MJ for HDRD.^{footnote 48} These LCA CI values were determined based on Canadian data and other lifecycle assessment tools, and were compared to fuel pathways submitted to British Columbia and California.

Table 4 shows the amount of fossil and low-carbon fuels supplied in Canada in the regulatory scenario between 2022 and 2030. In 2023, it is estimated that there will be 130 petajoules (PJ) of low-carbon fuel supplied in Canada. In 2026, credits from baseline activities and banked credits will no longer be sufficient to fulfill the annual CI reduction requirement. Therefore, it is estimated that biodiesel blending in diesel and LFO will increase above baseline levels in 2026 (at 142 PJ) while ethanol blending in gasoline and HDRD blending in diesel and LFO will increase above baseline levels in 2027 (at 180 PJ). Blend levels are assumed to increase linearly to the assumed blend rates in 2030 (at 293 PJ). The annual supply of low-carbon fuels remains relatively constant at 2030 levels between 2031 and 2040.

Table 4: Fossil and low-carbon fuels supplied in the regulatory scenario (PJ)
Note: Figures may not add up to totals due to rounding.
	2022–2025	2026–2029	2030	2031–2040	Total
Gasoline	5 609	5 327	1 251	10 947	22 684
Diesel	5 206	4 969	1 199	12 147	23 520
LFO	270	224	50	458	1 002
Ethanol	404	404	109	904	1 752
Biodiesel	126	209	69	686	1 071
HDRD	98	231	82	819	1 229

The Regulations will provide incentive for low-carbon fuel suppliers to obtain more credits by reducing the CI of the low-carbon fuels they supply. The reduction of the CI values of low-carbon fuels in California’s LCFS system has been demonstrated since the program began in 2011. This is partly due to lowering of the CI of the electricity grid in California, improved agricultural practices, increased efficiency in production, as well as the use of lower CI feedstocks.^{footnote 49} However, there is uncertainty as to how much the CI values of these fuels might decline over time. Therefore, it is assumed that the lifecycle CIs of low-carbon fuels remain constant over time. Uncertainty around how CI values may change over time is addressed in the uncertainty of impact estimates section.

Table 5 shows the total number of credits estimated for supplying low-carbon fuels by fuel type between 2022 and 2030. Primary suppliers who have surplus compliance units under the RFR will be able to convert these units into credits under the Regulations. Therefore, there will be a one-time rollover of credits from the RFR in 2024 estimated at 1.4 million based on departmental data from the RFR. In 2023, credits from low-carbon fuel blending are estimated at 6.1 million, increasing to 8.5 million in 2026, and 11.3 million in 2030. Between 2031 and 2040, annual credits for supplying low-carbon fuels decline slightly from 2030 levels.

Table 5: Credits from low-carbon fuels by fuel type (millions)
Note: Figures may not add up to totals due to rounding.
	2022–2025	2026–2029	2030	2031–2040	Total
Ethanol	11.7	13.9	3.4	28.1	57.0
Biodiesel	5.8	12.3	3.8	37.9	59.8
HDRD	5.2	12.5	4.2	42.0	63.9
Total	22.7	38.7	11.4	108.0	180.8

Attribution of supplying low-carbon-intensity fuels to the Regulations

In the baseline scenario, the federal RFR requires fossil fuel producers and importers to have an annual average of 5% renewable fuel content in gasoline (met with ethanol) and 2% renewable fuel content in diesel fuel and heating distillate oil (met with biodiesel and HDRD) based on volume. Some provinces blend at higher rates due to their own renewable fuel requirements and low-carbon fuel standards, which have increased the national average blend rate in recent years beyond the levels required under the federal RFR. The same volume of renewable fuel used to meet these federal and provincial regulations may be used to create a credit under the Regulations. Given that these actions would have occurred in the absence of the Regulations, they will not result in incremental costs or GHG emissions reductions.

In the absence of the Regulations, the likelihood of increased blending above existing federal and provincial blend requirements and policies is low as increased blending would generally be more expensive than maintaining the status quo. Given this, the increased use of low-carbon fuels above baseline levels is expected to be attributable to the Regulations. Therefore, costs and associated emission reduction benefits that are expected to occur above baseline levels will be attributable to the Regulations.

GHG benefits of blending low-carbon-intensity fuels

Blending higher levels of low-CI fuel with fossil fuel is expected to result in increased domestic GHG emissions reductions. To estimate emissions reductions, it is assumed that the fuel used in Canada remains constant on an energy basis between the baseline and regulatory scenarios. Therefore, the incremental amount of fossil fuel displaced is equal to the amount of incremental low-carbon fuel supplied on an energy basis.

Table 6 shows the estimated incremental amount of low-carbon fuel supplied domestically due to the Regulations. In the regulatory scenario, it is expected that low-CI fuel blending will increase above baseline levels by 2025 given that credits from baseline activities and banked credits will no longer be sufficient to fulfill the annual CI reduction requirement. Incremental blending is assumed to increase linearly from 2025 to 2030, reaching the assumed blend rate in 2030. Between 2031 and 2040, annual incremental low-carbon fuel supplied declines slightly from 2030 levels.

Table 6: Incremental low-carbon fuel supplied by fuel type (PJ)
Note: Figures may not add up to totals due to rounding.
	2022–2025	2026–2029	2030	2031–2040	Total
Ethanol	2	41	17	146	206
Biodiesel	17	100	36	356	508
HDRD	8	121	49	489	666
Total	27	262	101	991	1 381

Incremental domestic emissions reductions were quantified by subtracting the estimated emissions in the baseline scenario from emissions in the regulatory scenario. Emissions for each scenario were calculated by multiplying end-use combustion emission intensities by the amount of fuel supplied domestically in each scenario. This is equivalent to multiplying the incremental low-carbon fuel supplied by the difference between the emission intensity for fossil fuels and the emission intensity for low-CI fuels. The weighted national average emission intensities used for each fuel are presented in Table 7 (from the Departmental Reference Case). For more information on the difference between lifecycle carbon intensities and combustion emission intensities, please refer to the section above on lifecycle analysis versus national inventory accounting.

Table 7: Combustion emission intensity values by fuel type (in gCO₂e/MJ)
Fuel type	Emission intensity value
Gasoline	71.67
Diesel	71.73
LFO	71.16
Ethanol	2.40
Biodiesel/HDRD	5.92

It is estimated that the incremental GHG emissions reductions are about 91 Mt over the time frame of analysis from blending low-carbon fuels with fossil fuels. GHG emission reductions are shown in Table 8, by blend pathway.

Table 8: Total GHG emissions reductions by blend pathway (in Mt CO₂e)
Note: Figures may not add up to totals due to rounding.
Blend pathway	2022–2025	2026–2029	2030	2031–2040	Total
Ethanol in gasoline	0	2.9	1.2	10.1	14.3
Biodiesel and HDRD in diesel	1	13.9	5.3	53.3	73.5
Biodiesel and HDRD in LFO	0	0.7	0.3	2.5	3.6
Total	1.3	17.5	6.7	65.8	91.3

Costs of blending low-carbon fuels

To meet increased low-carbon fuel demand due to the Regulations, terminals will have to store fossil fuels with higher volumes of low-carbon fuel. It is expected that they will incur capital and operating costs to install or upgrade infrastructure (such as the installation of additional storage or shipping capacity). There are approximately 87 primary terminals in Canada, about 43 have blending capacity and about 44 are without blending capacity.^{footnote 50} Based on stakeholder consultations, costs to upgrade facilities without blending capacity will be around $10 million per site.

For biodiesel, it is estimated that approximately 25 primary terminal sites will need additional/new biodiesel blending capacity. About half of the biodiesel sites will be required to re-utilize tanks and equipment at an average cost of about $5.5 million per site, and the other half will be required to build a new tank for an additional $2 million per site ($7.5 million). In addition, it is estimated that approximately five primary terminal sites will require tankage and piping work for HDRD receipt and blending at about $5 million per site.^{footnote 51} It is assumed that it takes two years to build out terminal infrastructure.^{footnote 52} Therefore, capital costs for terminals are incurred in 2025 and 2026. It is estimated that total capital costs for terminals will be about $281 million over the time frame of analysis.

Retail and cardlock fuelling stations will have to provide blended fuel to end users. It is assumed that fuelling stations are currently equipped to handle up to 5% biodiesel.

To blend higher levels of low-carbon fuel with fossil fuel, refiners and terminals will also incur net incremental operating costs for supplying low-carbon fuels, estimated at $7,622 million between 2022 and 2040. Net incremental operating costs to supply low-carbon fuels were calculated by subtracting the incremental fossil fuel production cost savings by the incremental low-carbon fuel costs. To obtain incremental fossil fuel production cost savings, wholesale fossil fuel prices were applied to the incremental amount of fossil fuel displaced. To obtain incremental low-carbon fuel costs, wholesale low-carbon fuel prices and ongoing transportation costs were applied to the incremental amount of low-carbon fuel supplied.

To calculate wholesale prices, data from the Kent Group on average fossil fuel price margins by province between 2015 and 2019 were used to determine the differential between wholesale fuel prices and retail fuel prices.^{footnote 53} The Canadian average differential between wholesale and retail fuel prices is estimated at 43% for the gasoline pool and 38% for the diesel pool. These wholesale price differentials were then applied to retail fossil fuel price forecasts from the Departmental Reference Case in order to estimate wholesale gasoline and diesel price forecasts.

To calculate ethanol and biodiesel prices, energy-equivalent price differentials between low-carbon fuels and fossil fuels were calculated using data from the U.S. Department of Agriculture on average gasoline, diesel, ethanol, and biodiesel prices from 2015 to 2019.^{footnote 54} The estimated price differential is 24% between ethanol and gasoline, and 17% for biodiesel and diesel. These differentials were applied to the wholesale price forecasts for gasoline and diesel in order to obtain ethanol and biodiesel price forecasts. For HDRD, no price indices exist. As a result, a literature review was conducted to determine representative volumetric HDRD prices.^{footnote 55} Due to price uncertainty, an average of a high and low estimate of HDRD was calculated, and an average energy-equivalent price differential was estimated between biodiesel and HDRD of 20%.^{footnote 56}

In addition, ethanol and biodiesel are primarily transported by other means than fossil fuel pipelines because of operational challenges such as their ability to pick up water, degrade jet fuel quality, affect materials used in transportation and storage systems and because the existing pipeline infrastructure does not always line up with where biofuels are produced or available. It is therefore expected that there will be incremental ongoing transportation costs to deliver ethanol and biodiesel by rail or other modes of transportation.^{footnote 57} Therefore, it is assumed that refiners and terminals will incur ongoing transportation costs of about $0.05 per litre of incremental ethanol and biodiesel demanded.^{footnote 58}

In total, capital costs are estimated at $281 million and operating costs are estimated at $7.6 billion over the time frame of the analysis. Overall, supplying low-carbon fuels under the Regulations is estimated to result in a total compliance cost of $7.9 billion between 2022 and 2040.

Potential impacts from indirect land use change

Direct land-use change (DLUC) happens when a particular parcel of land is converted to grow crops for biofuel production. Indirect land-use change (ILUC) occurs when crops grown for biofuels displace traditional food and animal feed crops, leading to production of that displaced food crop elsewhere (i.e. other land is converted to grow the food crop). If new agricultural land expands into areas with high carbon stock such as forests, wetlands and peat land this leads to additional GHG emissions. If it occurs in a highly biodiverse land, it could result in biodiversity loss.

The Regulations are designed to prevent these impacts in two ways. The Fuel LCA Model will account for GHG impacts of DLUC in the CI of low CI fuels, and the Regulations will include criteria to prevent adverse land-use and biodiversity impacts related to biofuel feedstock cultivation and harvesting. These land use and biodiversity (LUB) criteria apply to feedstock regardless of geographic origin, but feedstock are exempt if they are not biomass (e.g. fuel made from direct-air-capture CO₂) or if they have been deemed by the Department as “low-concern biomass feedstock” (e.g. municipal solid waste). Only biofuels made from feedstock that adhere to the LUB criteria are eligible for credits under the Regulations.

Other potential impacts of blending low-carbon fuels

Ethanol has a higher-octane value than gasoline, so refiners could choose to avoid processing higher-octane gasoline and produce lower-octane gasoline instead if they choose to blend more ethanol. Given this, there may be some potential for refiner cost savings.

Alternatively, if refiners choose to keep producing higher-octane gasoline, the blended fuel will have an overall higher-octane value in the regulatory scenario. Standards for Original Equipment Manufacturers have been implemented to provide high compression engines in cars to the North American market, which require fuel with higher-octane values. Mid-level ethanol blends (E15 to E25) coupled with high compression engines could lead to some efficiency improvements that may be sufficient to offset the lower energy content of ethanol. If this is the case, there could be some potential for more emissions reductions and some mitigation of costs to consumers.^{footnote 59,}^{footnote 60}

Higher blends of biodiesel in diesel could improve fuel lubricity and raises the cetane number of the fuel. Diesel engines depend on the lubricity of the fuel to keep moving parts from wearing prematurely. Given this, it is possible that as refiners blend more biodiesel, they could choose to lower the lubricity of petroleum diesel to save on costs.^{footnote 61}

Furthermore, increased blending of low-carbon fuels in fossil fuels is expected to result in changes to air quality. For more information on how the Regulations are expected to impact air quality, please refer to the impacts on air quality section below.

Compliance Category 3: Supplying fuel or energy to advanced vehicle technologies

The end user of fuel may change or retrofit a combustion device, for example an engine, to be powered by another fuel or energy source such as electricity or hydrogen in transportation. Supplying fuel or energy to advanced vehicle technologies does not directly reduce the CI of the fossil fuel but reduces GHG emissions by displacing the fossil fuel with a fuel or energy source that has a lower CI.

The Regulations will allow credit creation for some fuels and energy sources supplied to the transportation sector. Quantities of low-carbon energy supplied to certain classes will be eligible to create credits. These fuels or energy sources will include hydrogen in fuel cell vehicles or other vehicles, electricity in electric vehicles, natural gas and renewable natural gas (including compressed and liquefied) in natural gas vehicles, and propane and renewable propane in propane vehicles. Electricity supplied to rail vehicles, however, will not be eligible for credit creation.

Supplying electricity to electric vehicles and natural gas/propane to natural gas/propane vehicles are the two representative pathways that have been modelled for Compliance Category 3. This is because there is little to no uptake of other fuels or energy sources in transportation in Canada (such as renewable natural gas and hydrogen). These are still emerging technologies and there is not enough information on them to estimate their likely uptake in Canada by 2030. However, the Regulations will provide an incentive for these kinds of technologies.

Supplying electricity to electric vehicles (EVs)

For homes equipped with charging stations connected to a network, the charging network operator will be the default credit creators. Charging network operators will also be the default credit creators for public charging. Private or commercial charging will create credits for site hosts by default.

Credit-creation: Credits will be created in accordance with the following formula based on the energy efficiency ratio of the vehicle class (R_ee), the liquid class credit reference CI value (CI_ref) [see Table 1 above], the lifecycle emissions of the electricity used to propel the EVs (CI_e), the quantity of electrical energy of a given CI supplied to the EVs (Q) and the energy density of electricity (D).

Credits = [(R_ee × CI_ref) – CI_e] × Q × D × 10^-6

Energy demand forecasts for EVs were obtained from an adjusted Departmental Reference Case. The adjustment assumes 50% LDVs sold in 2030, and 100% LDVs sold in 2035 will be EVs. Electricity that is supplied by a charging station that is installed in a residence no later than December 31, 2030, will be eligible for creating full credits until December 31, 2035. After this time, no residential charging will be eligible for credit creation. Any new residential charging stations installed after December 31, 2030, will not be eligible for credit creation. Given this, it is assumed that 28% of light-duty EV energy demand from the Reference Case is from public charging, the remaining 72% of demand is from home charging. The Regulations also require that all EV charging data be collected by a charging station that measures and communicates charging data to a charging network operator. Thus, it is assumed that 7.5% of light-duty EV energy demand is from residential charging stations capable of collecting and communicating charging data to a charging network operator. It is also assumed that this value will grow by about 2.5% each year based on consultations with stakeholders.^{footnote 62} As a result, these factors were also applied to Reference Case energy demand estimates for light-duty vehicle (LDV) EV charging. Table 9 presents EV energy demand estimates over the time frame of analysis.

Table 9: EV energy demand estimates by vehicle category (PJ)
Note: Figures may not add up to totals due to rounding.
	2022–2025	2026–2029	2030	2031–2040	Total
LDV-LDT	12	47	24	341	426
HDV	1	3	1	26	31
Buses	22	20	5	61	108
Total	35	70	30	428	558

Credits for supplying electricity to EVs are calculated using constant 2016 lifecycle CI electricity values by province. The electricity CI values vary depending on the mix of the electricity grid in each province. For example, provinces that rely more on natural-gas powered electricity will have a higher CI value than provinces that rely more on hydroelectric power. The Canadian average electricity CI value is 180.4 tonnes per gigawatt hour (t/GWh). An energy efficiency ratio (EER) of 4.1 was used for light-duty vehicles (LDV) and trucks (LDT), and an EER of 5.0 for buses and heavy-duty vehicles. Given this, Table 10 shows EV credit estimates over the time frame of analysis.

Table 10: EV credit estimates by vehicle category (millions)
Note: Figures may not add up to totals due to rounding.
	2022–2025	2026–2029	2030	2031–2040	Total
LDV-LDT	3.4	13.3	6.3	88.5	111.5
HDV	0.4	1.2	0.5	9.8	11.9
Buses	0.6	1.0	0.3	6.2	8.1
Total	4.4	15.5	7.0	104.5	131.5

Given the relative infancy of certain EV classes compared to their internal combustion engine (ICE) counterparts, some projections of future EV uptake vary substantially from what is estimated above. Barriers to wide-scale EV adoption include costs, technical limitations, infrastructure, and market dynamics and technological constraints, including range limitation and charging times. Moreover, infrastructure requirements for EVs are complex when compared to fossil fuel-related infrastructure already in place. While attitudes towards EVs for commercial and industrial applications are evolving and government incentive programs are helping to increase adoption rates, the current dominant market preference remains for ICE vehicles. Factors pushing towards increased EV adoption include increasing market familiarity with the technology, improvements in battery range and charging times, expanding infrastructure, and decreasing costs. Given the wide variability among forecasts, a sensitivity analysis on the number of credits created for supplying fuel and energy to advanced vehicle technologies is presented in the Uncertainty of impact estimates section.

Attribution and incremental impacts: It is expected that the EV market will continue to expand in the baseline scenario in the absence of the Regulations, with corresponding increases in electricity consumption as a substitute to gasoline and diesel. Other policies, such as the federal light duty vehicle (LDV) ZEV sales mandate, will also create incentives for EV uptake and infrastructure to be built.

Primary suppliers will have the option to acquire credits by trade from charging network operators and site hosts, therefore acting as a subsidy. This subsidy on its own will not likely be sufficient to incentivize investment that supports measurable incremental EV uptake. However, it will provide another incentive that could work in conjunction with other federal and provincial EV policies to boost market signals for increasing EV deployment. This analysis does not take that impact into account.

Supplying natural gas and propane to natural gas and propane vehicles

For compressed and liquefied natural gas and propane, including the fossil portion of any blend with a renewable fuel component, the fuelling station owner or operator will be the default credit creator for fuelling for transportation purposes. The credits will be created in the liquid class as this represents a displacement of liquid transportation fuel.

Credit-creation: Credits will be created in accordance with the following formula based on the liquid class credit reference CI value (CI_ref) [see Table 1 above], the lifecycle CI, the volume (Q) and the energy density (D) of compressed natural gas (CNG), liquefied natural gas (LNG) or propane supplied.

Credits = [CI_ref – CI_LNG_,_CNG_,_propane] × Q × D × 10^-6

Energy demand from natural gas and propane powered vehicles is estimated at 7 PJ in 2022, increasing to 9 PJ in 2030, and to 13 PJ by 2040. For the purpose of this analysis, credits for supplying natural gas/propane in transportation are calculated using constant lifecycle CI values of 67 gCO₂e/MJ for CNG, 75 gCO₂e/MJ for LNG, and 75 gCO₂e/MJ for propane. It is assumed that 50% of the natural gas demand is CNG and 50% is LNG. No EER values are mentioned in the formula as the EER values are close to one for these pathways. Using energy demand forecasts from the Departmental Reference Case, it is estimated that 0.06 million credits will be created in 2022, increasing to 0.09 million in 2030, and to 0.12 million credits by 2040. The analysis does not take into account the updated CI values in the Fuel LCA model for natural gas and propane that would result in fewer credits.

Attribution and incremental impacts: This pathway on its own will not likely be sufficient to incentivize investment that supports measurable incremental natural gas/propane uptake in transportation. As with EVs, however, this pathway will provide another incentive that could work in conjunction with other federal and provincial policies to boost market signals for increasing deployment of natural gas and propane vehicles. This analysis does not take that impact into account.

Impacts from the Compliance Fund

The Regulations will establish a Compliance Fund as a flexibility mechanism. Primary suppliers will be able to contribute to this compliance fund mechanism for up to 10% of their annual reduction requirement. The credit price under the fund will be set in the Regulations at $350 in 2022 nominal dollars per compliance credit (CPI adjusted), which corresponds to $343 in 2021 dollars. Any contributions to the fund must be used for projects or activities that reduce emissions within a five-year period from the time the contribution is made. This analysis treats the fund contributions as if they are transfer payments. Thus, impacts from the fund are presented as equal and offsetting costs to industry (payments) and benefits to society (assets for investments to reduce GHG emissions).

It is estimated that the fund will be used initially in 2025 for about 0.3% of the credit requirement, equivalent to about 45 thousand credits. Between 2026 and 2038, it is estimated that the fund will be used up to the full 10% limit at 3.4 million credits in 2030. In 2039, it is estimated that use of the fund will decline as credits from supplying fuel or energy to advanced vehicle technologies increase over time and the credit requirement of 14 gCO₂e/MJ stays constant. Estimates of fund assets and payments over the time frame of analysis are presented in Table 11.

Table 11: Estimates of fund assets and payments (millions of dollars)
Note: Figures may not add up to totals due to rounding. Monetized values are discounted to present value using a 3% discount rate.
	2022–2025	2026–2029	2030	2031–2040	Total Present Value
Fund assets	14	3,055	929	7,001	10,999
Fund payments	-14	-3,055	-929	-7,001	-10,999

Quantification of eventual GHG reductions from the fund is not possible at this time and is beyond the scope of this analysis. This is because the specific projects that will receive support in the future from the fund are unknown at this time. Without information on project parameters, it is not possible to estimate incremental GHG emission reductions. However, given that the fund will be required to deliver real, short-term, traceable reductions, it is expected to contribute to the objective of the Regulations to achieve GHG reductions.

Emerging technology pathways

Emerging technologies are technologies that are at a lower technological readiness level, or those that are at a high technological or commercial readiness level but have low adoption rates due to various reasons such as cost, asymmetric information, or lack of incentive. It is expected that the Regulations will provide a sufficient incentive to increase the adoption of emerging technologies to reduce GHG emissions. Examples of emerging technologies that could receive credits under the Regulations include co-processing low-CI feedstock at refineries, hydrogen in fuel cell vehicles, renewable natural gas in natural gas vehicles; renewable electricity at fossil fuel facilities, and emerging low-CI fuels such as synthetic fuels from direct air capture. However, because emerging technologies have low adoption rates, there is not a lot of data available on costs. Credits for emerging technologies are assumed to be incremental and cost the same as the fund ($343 per credit in 2021 dollars). Given this, it is assumed that emerging technology credits make up the difference between the amount of credits required and credits created from mature technologies plus credits obtained from payments to the fund.^{footnote 63}

By 2026, it is assumed that banked credits, credits from mature technologies, and fund contributions will no longer be sufficient to fulfill the credit requirement. Thus, 3.9 million credits from emerging technologies will be required. Credits from emerging technologies are estimated to gradually increase to a maximum in 2030 at 8.3 million, and then gradually decrease each year after until 2038 when they are no longer needed due to a crowding out effect from increasing baseline credits created from supplying fuel or energy to advanced vehicle technologies and a constant annual CI reduction requirement. As a result, the associated incremental costs and GHG reductions follow the same trend. Incremental impacts from emerging technologies are presented in Table 12 between 2022 and 2040.

Table 12: Incremental costs and GHG reductions from emerging technologies
Note: Figures may not add up to totals due to rounding. Monetized values are discounted to present value using a 3% discount rate.
	2022–2025	2026–2029	2030	2031–2040	Total Present Value
Costs (millions of dollars)	0	6,879	2,254	7,993	17,126
GHG reductions (Mt CO₂e)	0	23.8	8.3	32.6	64.7

The CI reduction requirements after 2030 will be subject to a review of the Regulations and potential future amendments.

Impacts on air quality

Some of the representative pathways are expected to result in changes to the emissions of air pollutants, which would therefore result in changes to air quality. Air pollutants are substances that affect human health and the environment (such as ground level ozone, particulate matter, and acid rain).^{footnote 64} Air pollutants can be grouped into four different categories: criteria air contaminants and related pollutants (e.g. ozone, particulate matter, sulphur oxides, nitrogen oxides, volatile organic compounds, etc.), persistent organic pollutants (e.g. dioxins and furans), heavy metals (e.g. mercury), and toxics (e.g. benzene). These air pollutants are all different. They differ in their chemical composition, reaction properties, emission sources, how long they last in the environment before breaking down, their ability to move long or short distances, and their eventual impacts.^{footnote 65}

The likely impact on air pollutant emissions from Compliance Category 1 is unknown, and has not been assessed. However, these impacts are likely to be minimal. Air pollutant emissions from gasoline vehicles and engines are already regulated to a significant extent under existing regulations such as the Regulations Amending the Sulphur in Gasoline Regulations, which limit the sulphur content of gasoline.^{footnote 66} Refining sector emissions are also regulated through the Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector).^{footnote 67} In addition, given the flexibility of the proposed Regulations in regard to the choice of compliance pathway, it is unknown where, and by how much, air pollutant emissions would change.

The impact of the proposed Regulations on air quality due to blending low-carbon fuels is also expected to be minimal. A previous risk assessment conducted by Health Canada on the health risks and benefits associated with the use of ethanol-blended gasoline compared to unblended gasoline indicated that increasing the use of E10 fuel in Canada would result in a possibly negligible decrease in the number of adverse health effect incidents.^{footnote 68} This decrease would result from a reduction in ambient air concentrations of select pollutants resulting from E10 fuel use. In general, there were no substantial differences in predicted health effects between the conventional gasoline baseline and E10 fuel scenarios. No further study was conducted to evaluate ethanol blends up to E15.

In addition, previous analyses by Health Canada indicated that the widespread use of B5 or B20 nationally is expected to result in minimal air quality and health benefits/risks, and these are likely to diminish over time.^{footnote 69} This earlier conclusion was based on evidence available in 2012. More recent evidence from the United States suggests that the use of B20 in modern engines may result in increases in emissions of some air pollutants compared to the use of ultra-low sulphur diesel fuel (ICCT 2021). The air quality impacts in the Canadian context and any associated air pollution health impacts have not been estimated.

Currently, there is limited information regarding the air quality impacts associated with increased HDRD blending in diesel.

Summary of credits created

Early credit creation starts upon registration of the Regulations. Early action credits are created for baseline actions (e.g. low-carbon fuels supplied for federal/provincial blending mandates, supplying fuel or energy to advanced vehicle technologies) for up to twelve months before the coming into force on July 1, 2023, of the annual reduction requirements under the Regulations. Credit creation from baseline pathways plus banked credits from previous years are sufficient to fulfill the credit requirement and result in an accumulation of banked credits for the first two years that the Regulations are in force (2023–2024). In 2025, credits from baseline pathways and banked credits are estimated to no longer be sufficient to fulfill the credit requirement. As a result, it is estimated that incremental actions (e.g. CCS, blending low-CI fuels) will be required starting in 2025. It is estimated that 2025 is the last year in which banked credits are used and the first year in which the fund is accessed. In 2026, it is estimated that credits from emerging technologies will be required to fulfill the credit requirement. By 2030, the Regulations reach full stringency at 14 gCO₂e/MJ and blending of low-carbon fuels will be used to the assumed blend rates (10% for ethanol, 5% for biodiesel and 6% for HDRD). The fund will also be accessed to the regulatory limit of 10% and emerging technology credits will be needed to meet the credit requirement. Credit estimates between 2022 and 2030 are presented in Table 13. Credit cost estimates by pathway are presented in Table 14.

Table 13: Credit estimates between 2022 and 2030 (millions)
Note: Figures may not add up to totals due to rounding.
	2022	2023	2024	2025	2026	2027	2028	2029	2030
Baseline credits	3.7	9.7	8.8	9.5	10.0	10.7	11.7	12.8	14.6
Banked credits	0	3.7	8.7	3.8	0	0	0	0	0
Incremental credits	0	0	0	4.0	9.0	11.6	13.5	15.3	16.3
Fund	0	0	0	0	2.0	2.5	2.8	3.1	3.4
Credits created and banked	3.7	13.4	17.5	17.5	21.2	24.7	28.0	31.2	34.3
Credits required	(0)	(4.7)	(13.7)	(17.5)	(21.2)	(24.7)	(28.0)	(31.2)	(34.3)
Net credits	3.7	8.7	3.8	0	0	0	0	0	0

The estimated trend in total credits created between 2031 and 2040 slightly declines after 2030. However, as the credit requirement remains constant at 14 gCO₂e/MJ, credits from supplying fuel or energy to advanced vehicle technologies are estimated to increase over time, crowding out incremental credits and the fund. As a result, incremental credits decrease from 16.3 million in 2030 to 8.0 million in 2040 and the fund decreases from 3.4 million in 2030 to zero in 2040. Credit estimates by compliance category between 2022 and 2040 are presented in Figure 5.

Table 14: Summary of pathway cost and overall credits in 2030
Note: Figures may not add up to totals due to rounding.
Pathway	Credits (millions)	Cost per credit ($/credit)
Banked credits	-	-
Low carbon fuels from current mandate	6.4	-
Supplying fuel or energy to advanced vehicle technologies (EVs)	7.0	-
Supplying fuel or energy to advanced vehicle technologies (NGVs and propaneVs)	0.1	-
Baseline carbon capture and storage	1.1	-
Biodiesel (5%) in LFO	0.2	41
Biodiesel (5%) in Diesel	1.8	79
Incremental carbon capture and storage	3.0	125
HDRD (6%) in LFO	0.1	134
Ethanol in Gasoline (10%)	0.5	152
HDRD (6%) in Diesel	2.4	158
Fund	3.4	343
Emerging tech	8.3	343
Total credits created (quantity of credits supplied)	34.3	NA

Figure 5: Credit estimates by compliance category, 2022–2040 (millions)

Note: Credit estimates for supplying low-carbon fuels jump in 2024 due to the one-time roll-over of credits from the RFR, estimated at 1.4 million.

Figure 5: Credit estimates by compliance category, 2022–2040 (millions)

Summary of benefits

The Regulations will reduce GHG emissions that will otherwise be emitted into the atmosphere. It is estimated that the Regulations will result in 204 Mt of cumulative GHG emission reductions that are attributable and measurable over the time frame of this analysis, as shown in Table 15 below.

Supplying fuel or energy to advanced vehicle technologies could work in combination with other policies to further incentivize EV uptake but is not likely to result in measurable reductions attributable to the Regulations alone. In addition, by law, the fund will be required to invest in GHG emission reduction efforts. Given that the timing, magnitude and incrementality of these emission reduction efforts are unknown, the analysis is unable to estimate reductions for them. There is also uncertainty regarding the potential for actions taken throughout the fuel lifecycle and from potential emerging technologies. Uncertainty regarding the impacts of attribution assumptions have been assessed in a sensitivity analysis (see section on Uncertainty of impact estimates).

It is estimated that the Regulations will not result in incremental GHG emission reductions until 2025 since industry compliance is expected to be achieved by using credits from actions that will have occurred in the baseline between 2022 and 2024 (see section above on summary of credits created). Incremental GHG emission reductions peak in 2030 at about 18 Mt and are estimated to gradually decline each year after as the CI reduction requirements remain constant after 2030 and credits from supplying fuel or energy to advanced vehicle technologies crowd out the need to use credits from incremental pathways. The CI reduction requirements after 2030 are subject to a review of the Regulations and potential future amendments.

Table 15: Incremental GHG emission reductions by compliance category (Mt CO₂e)
Note: Figures may not add up to totals due to rounding.
	2022–2025	2026–2029	2030	2031–2040	Total
Actions along the lifecycle	3.0	12.0	3.0	30.0	48.0
Supplying low-carbon fuels	1.3	17.5	6.7	65.8	91.3
Emerging technologies	0	23.8	8.3	32.6	64.7
Total GHG reductions	4.3	53.2	18.0	128.5	204.1

Summary of industry compliance costs

It is expected that credits will be created under the Regulations for activities that will have otherwise occurred in the baseline scenario. As such, not all of the costs will be attributable to the Regulations. Incremental compliance costs attributable to the Regulations are estimated at $41.7 billion over the period of analysis and are presented in Table 16.

Table 16: Net compliance costs (millions of dollars)
Note: Figures may not add up to totals due to rounding. Monetized values are discounted to present value using a 3% discount rate.
	2022–2025	2026–2029	2030	2031–2040	Total Present Value
Net compliance costs	4,349	12,131	3,924	21,310	41,715

The Regulations result in incremental compliance costs in 2023 because most of the compliance pathways require upfront capital investments and lead time for projects to become operational. Early action credits and a low stringency in the early years of the Regulations allow time for a buildup of banked credits from baseline activities (such as credits from low-carbon fuels supplied under the RFR). This accumulation of banked credits in the early years is expected to provide firms with enough lead time to make capital investments in projects required by 2030, when the Regulations reach full stringency. As a result, operating costs are not incurred until 2025 since industry compliance is expected to be achieved by using banked credits from baseline actions between 2022 and 2024 (see section above on summary credits created). Net operating costs increase gradually from 2025 to 2029, reaching their peak in 2030 (at $3,924 million). Net operating costs gradually decline between 2031 and 2040 due to more baseline credits from supplying fuel or energy to advanced vehicle technologies that reduces the need to use credits from incremental pathways. Estimates of net compliance costs by compliance category are shown in Table 17.

Table 17: Net compliance costs by compliance category (millions of dollars)
Note: Figures may not add up to totals due to rounding. Monetized values are discounted to present value using a 3% discount rate.
	2022–2025	2026–2029	2030	2031–2040	Total Present Value
Actions along the lifecycle	3,931	546	127	1,081	5,686
Supplying low-carbon fuels	404	1,652	614	5,234	7,904
Emerging technologies	0	6,879	2,254	7,993	17,126
Fund payments	14	3,055	929	7,001	10,999
Net compliance costs	4,349	12,131	3,924	21,310	41,715

Industry and government administrative costs to ensure compliance

The Regulations will require primary suppliers to keep records and submit reports (including a registration report, a compliance report, and verification reports). They will also incur costs to submit information on credit creation activities and third-party verification of reports. In addition, primary suppliers and renewable fuel producers and importers who were previously regulated under the Renewable Fuels Regulations (RFR) will benefit from some administrative cost savings due to the repeal of the RFR. As a result, net administrative costs to primary suppliers are estimated at $64.8 million over the time frame of analysis. Administrative cost savings to primary suppliers and renewable fuel producers and importers are estimated at $7.2 million from 2022 to 2040. As a result, there will be total net administrative costs to industry estimated at $57.6 million between 2022 and 2040.^{footnote 70}

The Department will incur opportunity costs to enforce and administer the Regulations. With respect to enforcement costs, it is expected that there will be costs required to hire and train new enforcement officers, training for current enforcement officers, costs for equipment, and costs for inspections. In total, enforcement costs are estimated at $10.3 million between 2022 and 2040.

Program implementation opportunity costs include the hiring and training of new full-time employees, training and equipment, policy analysis, data collection and analysis, verification of third-party verifiers, compliance promotion, as well as reporting and information management. The Department will also incur administrative costs related to the design and development of a credit transaction system, the Fuel Lifecycle Assessment Model, and the electronic reporting system. Resources will also be required in order to operate the credit transaction system, verify compliance pathways, as well as to update these tools and systems. In total, program costs for the Regulations are expected to be about $73.0 million between 2022 and 2040.

Table 18: Administrative costs for industry and Government (millions of dollars)
Note: Figures may not add up to totals due to rounding. Monetized values are discounted to present value using a 3% discount rate.
	2022–2025	2026–2029	2030	2031–2040	Total
Industry administrative costs	9.8	13.2	3.6	38.2	64.8
Industry administrative cost savings	(0.8)	(1.6)	(0.4)	(4.4)	(7.2)
Government administrative costs	29.0	19.0	4.4	37.5	89.8
Net administrative costs	37.9	30.5	7.6	71.4	147.4

Total net industry administrative costs are estimated at $57.6 million between 2022 and 2040, and total government administrative costs to implement and enforce the Regulations are estimated at $89.8 million over the time frame of analysis. Total administrative costs to industry and government necessary to ensure compliance with the Regulations are estimated to be $147.4 million between 2022 and 2040.

Cost-effectiveness analysis of central case results

Between 2022 and 2040, the Regulations are estimated to result in GHG emission reductions of 204 Mt at a cumulative cost of $41.8 billion to industry and government and a net cost of $30.8 billion to society over the time frame of analysis. Table 19 presents a summary of central case impacts.

Table 19: Central case impacts (millions of dollars)
Note: Figures may not add up to totals due to rounding. Monetized values are discounted to the present value using a 3% discount rate.
	2022–2025	2026–2029	2030	2031–2040	Total Present Value
Credit creation costs	4,335	9,077	2,995	14,309	30,715
Fund payment costs	14	3,055	929	7,001	10,099
Administrative costs	29	19	4	38	83
Fund asset benefits	(14)	(3,055)	(929)	(7,001)	(10,999)
Administrative cost savings	(1)	(1)	(0)	(3)	(6)
Net costs	4,363	9,094	2,999	14,343	30,793
GHG emission reductions (Mt)	4	53	18	128	204

To obtain the cost per tonne estimate of the Regulations, costs to industry and government are divided by the amount of the GHG emissions reduced between 2022 and 2040. To obtain the net cost per tonne estimate of the Regulations, costs to industry and government less benefits to society are divided by the amount of the GHG emissions reduced between 2022 and 2040. In this analysis, only the monetized costs are discounted. The GHG emission reductions are left undiscounted. The analysis was done this way to show what the costs of the Regulations will be to achieve the estimated amount of GHG emission reductions in their physical form. Therefore, the anticipated GHG emission reductions will be achieved at an estimated cost per tonne of $205 and a net cost per tonne of $151 (see Table 20).

Table 20: Central case cost-effectiveness analysis (2022–2040)
Note: Figures may not add up to totals due to rounding. Monetized values are discounted to the present value using a 3% discount rate. GHG emission reductions are undiscounted.
	2022–2025	2026–2029	2030	2031–2040	Total Present Value
Cost (millions $)	4,384	12,130	3,924	21,307	41,709
Net cost (millions $)	4,363	9,094	2,999	14,343	30,793
GHG reductions (Mt CO₂e)	4	53	18	128	204
Cost per tonne ($/tCO₂e)					205
Net cost per tonne ($/tCO₂e)					151

Uncertainty of impact estimates

The results of this analysis are based on key parameter estimates, which may be higher or lower than indicated by the projections and assumptions relied on to develop the analysis. For example, the modelling relies on assumptions about the proportion of category 1, 2 and 3 credits that will be created and at what cost. These assumptions account for the costs of known, mature technologies as well as assumptions about emerging technologies. It relies on projections of energy demand and prices. Furthermore, it follows TBS guidance on federal cost-benefit analyses of regulations, which requires the use of a 3% discount rate when a regulation has health or environmental impacts.

Given this uncertainty, sensitivity analyses were conducted to assess the impact of changes to these parameters on the expected impacts of the Regulations, where possible between 2022 and 2040.

Credit creation: The estimated number of credits created for each compliance pathway may be higher or lower than estimated in the central analysis, and consequently the estimated incremental costs and reductions (impacts are shown in tables 25 and 26 below). Feedback from stakeholders was solicited by the Department, which yielded a range of results. Additionally, it is expected that changes in energy demand and future technological advances could result in significantly higher than estimated credits. To estimate the effect of different credit estimates on the final results, sensitivity analyses were conducted for seven scenarios:

(1) Fewer credits from actions along the lifecycle: where CCS credits are 50% lower than the central case. There is uncertainty regarding firms’ ability to make investments in GHG reducing projects. For example, if unanticipated technological barriers arise credit creation from CCS would be lower than estimated. In this scenario, 2030 credits for actions along the lifecycle are estimated to decrease from 4.1 million to 2.6 million. From 2022 to 2040, more fund contributions and credits from emerging technologies will be needed, which are both estimated to be the highest cost pathways in the analysis (at $343/credit). The fund is treated as if it is a transfer payment since the specific projects that will receive funds are unknown (i.e. no estimated GHG reductions and costs). As a result, this scenario leads to less GHG reductions and higher costs. Between 2022 and 2040, this will result in a net cost per tonne of about $165 (higher than the central case).
(2) More credits from actions along the lifecycle: where CCS credits are 100% higher than the central case. This may be more likely if technological advancements are greater than anticipated. In this scenario, 2030 credits for actions along the lifecycle are estimated to increase from 4.1 million to 7.1 million. From 2022 to 2040, fewer fund contributions will be required and credits from emerging technologies will not be needed at all, resulting in more GHG reductions and lower costs. Between 2022 and 2040, this will result in a net cost per tonne of about $125 (lower than the central case).
(3) Fewer credits from supplying low-carbon fuels: where the 2030 blend levels of low-carbon fuels are lower with biodiesel in diesel and LFO at 3%, and HDRD in diesel and LFO at 3%, while ethanol remains constant at 10% in jurisdictions where there is no other blending mandate (in the central case, 2030 blend levels are 5%, 6%, 10% respectively). This represents a scenario in which there are more barriers for supplying low-carbon fuels than anticipated. For example, if global HDRD supplies are lower than anticipated. In this scenario, 2030 credits from supplying low-carbon fuels are estimated to decrease from 11.4 million to 8.7 million. Between 2022 and 2040, fund contributions will be higher and more credits from emerging technologies will be required. This results in greater costs but less GHG reductions given that the fund is treated as if it is a transfer payment, as mentioned above. Between 2022 and 2040, this will result in a net cost per tonne of about $186 (higher than the central case).
(4) More credits from supplying low-carbon fuels: where the global supply of HDRD is higher than anticipated and the 2030 blend level of HDRD in diesel and LFO is higher at 10% (in the central case, the 2030 blend level is 6%), while ethanol blend rates increase to 15% (compared to 10% in jurisdictions where there is no other blending mandate in the central case). The Regulations will also provide incentive for low carbon fuel suppliers to obtain more credits by reducing the CI of the low-carbon fuels they supply. However, there is uncertainty regarding how much LCA CI values may decline over time. In this scenario, LCA CI values for low-carbon fuels decline from 49 gCO₂e/MJ in 2022 to 41 gCO₂e/MJ in 2030 for ethanol, 26 CO₂e/MJ in 2022 to 17 gCO₂e/MJ in 2030 for biodiesel, and 29 gCO₂e/MJ in 2022 to 24 gCO₂e/MJ in 2030 for HDRD. In addition, 2030 credits from supplying low-carbon fuels are estimated to increase from 11.4 million to 17.5 million. Between 2022 and 2040, fund contributions and emerging technology credits will have a lower requirement. Holding all else constant, if the CI value of low-carbon fuels decreases, incremental GHG emission reductions from low-CI fuels will remain the same (more detail on this is included in the section above on lifecycle analysis versus national inventory accounting). Furthermore, as credits from low-CI fuels increase, the level of credits required will decrease given that low-carbon fuels will displace the use of fossil fuels. Therefore, GHG emission reductions and costs both decrease in this scenario, while reductions decrease less than the costs. Between 2022 and 2040, this will result in a net cost per tonne of about $111 (lower than the central case).
(5) Fewer credits from supplying fuel or energy to advanced vehicle technologies: where credits are 50% lower than the central case. This scenario could occur if EV or natural gas/propane vehicle uptake is lower than projected or if metered residential EV charging is lower than assumed. In this scenario, 2030 credits from supplying fuel or energy to advanced vehicle technologies are estimated to decrease from 7.1 million to 3.6 million. From 2022 to 2040, more credits from emerging technologies and contributions from the fund will be required, resulting in greater GHG reductions and costs. It will also result in a net cost per tonne of about $172 (higher than the central case).
(6) More credits from supplying fuel or energy to advanced vehicle technologies: where credits are 50% higher than the central case. This could represent a scenario where EV and/or natural gas/propane vehicle uptake is higher than anticipated. This could also occur if metered residential EV charging is higher than assumed. In this scenario, 2030 credits from supplying fuel or energy to advanced vehicle technologies are estimated to increase from 7.1 million to 10.7 million. Fewer emerging technology credits and fewer fund contributions will be needed. There will also be fewer credits from incremental actions (i.e. blending ethanol and HDRD) required over the time frame of analysis, resulting in fewer GHG reductions and costs. Between 2022 and 2040, this will result in a net cost per tonne of about $127 (lower than the central case).
(7) The fund is not used: and greater reliance on credits from emerging technologies is required to fulfill the credit requirement. In this scenario, 2030 fund contributions are estimated to decrease from 3.4 million to zero. From 2022 to 2040, more credits from emerging technologies will be required, which will result in greater GHG reductions and costs. This is because the fund is treated as if it is a transfer payment since the specific projects that will receive funds are unknown (i.e. no estimated GHG reductions and costs). Between 2022 and 2040, this will result in a net cost per tonne of about $169 (higher than the central case).

Price forecasts: The analysis will be sensitive to the assumptions and forecasts for energy prices over the relevant time period. To address this, the analysis has presented high and low scenarios for the price differential between low-carbon fuels and fossil fuels. In the low scenario, price differentials are 50% lower than the central case at 12% for ethanol and gasoline, 8% for biodiesel and diesel, and 11% for HDRD and biodiesel. In the high scenario, price differentials are 50% higher than the central case at 36% for ethanol and gasoline, 25% for biodiesel and diesel, and 28% for HDRD and biodiesel. It is estimated that the Regulations will result in a net cost per tonne of $136 for the low scenario (lower than the central case) and $166 for the high scenario (higher than the central case).

Discount rate: TBS recommends a 7% discount rate for cost-benefit analyses in most cases; however, for health and environmental analyses or when a regulation has impacts occurring over a long-time horizon, a lower discount rate (3%) is considered more appropriate. A sensitivity analysis was done to compare the central case (3%) to the higher discount rate (7%). It is estimated that this scenario will result in a net cost per tonne of $111 (lower than the central case).

Table 21: Sensitivity analysis of cost-effectiveness result (2022–2040)
Note: Values discounted to present value using a 3% discount rate, except in the case in which a 7% rate is used.
Variable(s)	Sensitivity Case	Net Costs (Millions)	GHG Reductions (Mt)	Net Cost per Tonne ($/tCO₂e)
Central case (from Table 20)	N/A	30,771	204	151
Credits from actions along the lifecycle	Fewer	33,171	201	165
Credits from actions along the lifecycle	More	26,770	214	125
Credits from supplying low-carbon fuels	Fewer	37,405	201	186
Credits from supplying low-carbon fuels	More	23,471	212	111
Credits from supplying fuel or energy to advanced vehicle technologies	Fewer	46,010	267	172
	More	19,157	151	127
Fund	Not used	41,815	248	169
Price differential: low-CI fuel versus fossil fuel	Lower	27,678	204	136
Price differential: low-CI fuel versus fossil fuel	Higher	33,864	204	166
Discount rate	7%	22,603	204	111

The social cost of carbon

The social cost of carbon (SCC) is a monetary measure of the net global damage from climate change that results from an additional metric tonne of carbon dioxide (CO₂) emissions for a given year. For federal regulations that result in changes in CO₂ emissions, the SCC is used to measure the quantifiable costs of emitting, or benefits of reducing, one tonne of CO₂ for a given year.^{footnote 71}

To calculate the social benefits from CO₂ emission reductions, the annual tonnes of CO₂ emissions reduced are multiplied by the SCC for each year in question. These monetized benefits are then discounted to present value, using a 3% discount rate, and are summed over the same time frame as the overall analysis. Since 2018, all federal regulatory analysis involving GHG emissions has relied on the SCC values that were published by the Department in 2016.^{footnote 72} These SCC values are derived from three commonly used peer-reviewed integrated assessment models: the Dynamic Integrated Climate-Economy (DICE) model, the Policy Analysis for the Greenhouse Effect (PAGE) model, and the Climate Framework for Uncertainty, Negotiation and Distribution (FUND) model. The central estimate based for the year 2020 is C$52/tCO₂ (in 2021 dollars).

There have been no recently published updates to the FUND model, but recent academic literature published by the authors of the DICE model and the PAGE model indicate that the previous iterations of their models that the Department used to develop its 2016 estimate of the SCC are out of date. For example, when using a constant 3% discount rate, the central SCC estimate for the year 2020 from the revised version of the DICE model is US$105/tCO₂ (C$136/tCO₂),^{footnote 73} which is more than double the value compared to the previous model iteration. This higher estimate is largely due to updates to global population estimates, data revisions to economic activity estimates, and incorporating new research on the carbon cycle.^{footnote 74} In addition, revisions to the PAGE model, which include climate science updates, economic updates, and novel developments such as incorporating the impact of non-linear Arctic feedbacks on the global climate system and economy, have also resulted in significant increases to its estimate of the SCC.^{footnote 75} The central estimate from the revised PAGE model for the year 2020 is US$344/tCO₂ (C$443/tCO₂),^{footnote 76} which is more than four times the value compared to the model iteration used to inform the Department’s current central estimate.

As a result, the Department concluded in 2020 that the current SCC values used for Canadian regulatory analysis likely underestimate climate change damages to society, and the social benefits of reducing GHG emissions. Moreover, in the Government of Canada’s Strengthened Climate Plan, A Healthy Environment and a Healthy Economy, the Government of Canada committed to revisiting its SCC estimates in use and ensuring that Canada’s methodology aligns with the best international climate science and economic modelling.^{footnote 77}

As part of that process, the Department has been evaluating the emerging scientific and economic literature as well as key developments related to the SCC internationally and at leading think tanks. For example, Bressler (2021) developed an extension to the DICE model to explicitly include temperature-related mortality impacts by estimating a climate-mortality damage function. The author found that incorporating mortality costs increased the SCC for the year 2020 from US$45 to US$312/tCO₂ (C$58 to C$401/tCO₂) in the baseline emissions scenario.^{footnote 78}

Furthermore, since publication of the proposed Regulations in the Canada Gazette, Part I, there have been a number of informative SCC-related developments in other jurisdictions, most notably in the United States. This includes the finalized guidance published by the New York State Department of Environmental Conservation, which recommends that State entities use a central SCC estimate of US$124/tCO₂ (C$159/tCO₂). The State of New York’s estimates relied on the original federal U.S. Interagency Working Group 2016 methodology,^{footnote 79} but used a 2% discount rate as the central value instead of 3%.^{footnote 80}

Lastly, the Department continues to monitor research and analysis from leading think tanks such as Resources for the Future. Recent research includes a Resources for the Future working paper by Rennert et al. (2021), which provides illustrative SCC estimates based on a variety of scenarios when key components used to generate the SCC are updated. When using a constant 3% discount rate, the authors found that the SCC for the year 2020 ranged from US$44 to US$192/tCO₂ (C$57 to C$248/tCO₂) depending on the socioeconomic trajectory employed.^{footnote 81}

As updated SCC estimates from the Department are not yet available, an interim approach continues to be used for the analysis of the Regulations where a range of updated SCC estimates from the above literature are considered in addition to the Department’s current SCC value. This is done to illustrate a range of plausible values once the Department updates its SCC estimate.

Break-even analysis

As there is inherent uncertainty concerning the estimates of avoided climate change damages, an integral part of this interim approach is to conduct a break-even analysis (BEA) to establish a range of benefits needed to offset the monetized costs of the Regulations. This approach is simple and transparent, offers a risk tolerance perspective, and provides continuity between previous and future climate change analyses.

BEA is a technique used to assess how valuable a non-monetized effect will have to be in order to meet or exceed net costs. It is most effective when analysts are particularly uncertain about one key parameter – in this case, the dollar value of social benefits from CO₂ emission reductions. In climate change policy, BEA involves determining the minimum carbon value that will allow a given regulation to break even (i.e. to ensure benefits at least equal costs). Consistent with methodologies used by other jurisdictions, to validate the break-even value, it should fall within a plausible range of similar values.^{footnote 82}

For the Regulations, the break-even value was determined by calculating the net societal cost per tonne of GHG emission reductions. As illustrated in Figure 6 below, the net societal cost per tonne is estimated to range between $111 and $186/tCO₂ with a central estimate of $151/tCO₂. These values were retrieved from the sensitivity analysis shown in Table 21 with the lower bound and upper bound values reflecting more credits and fewer credits being supplied from low-carbon fuels, respectively. To validate the break-even value, the net societal cost per tonne of the Regulations was compared to a plausible range of estimates found in the existing and emerging literature. This was done to illustrate what an updated SCC estimate might be, once the Department completes its review of the SCC. As illustrated in Figure 6 below, this includes the Department’s current central SCC value of $52/tCO₂ at the lower end of the range and an SCC value of $443/tCO₂ from the updated PAGE model at the upper end of the range.

Figure 6: Break-Even Plausibility

Figure 6: Break-Even Plausibility

Given the range of plausible estimates for the SCC, the BEA suggests that with the updated SCC estimates, it is plausible that the Regulations will yield a net benefit result.

Monte Carlo analysis

To further evaluate the impact of the Regulations, the Department calculated an estimate of the probability that the Regulations will break even. This type of analysis, known as Monte Carlo analysis, was conducted by specifying probability distributions for the net cost per tonne of the Regulations as well as the SCC. For the net societal cost per tonne of the Regulations, a triangular distribution was assumed, with $111 and $186/tCO₂ reflecting the lower and upper bounds, and $151/tCO₂ reflecting the peak of the triangle. For the SCC, a uniform distribution was assumed, and the Department’s central SCC value of $52/tCO₂ was used as a lower bound estimate while the SCC value of $443/tCO₂ was used as an upper bound estimate. Based on the feedback received from the expert peer review that was solicited during the Canada Gazette, Part I, comment period, it was communicated that the SCC estimates illustrated above accurately reflect the range of plausible values found in the scientific literature. Given this, for the purpose of this analysis it was assumed that any value between $52 and $443/tCO₂ is equally likely to occur.

Overall, the Monte Carlo simulation involving 10,000 pairs of values of social benefits and costs yielded a 75% probability that the Regulations will break even. Put differently, 75% of the time the Monte Carlo simulation yielded a net benefit result instead of a net cost result. Based on this analysis, the Department concludes that it is plausible that the Regulations would yield net benefits when using a forthcoming updated Departmental value for the SCC.

Distributional analysis of regulatory impacts

The Regulations will increase production costs for primary suppliers, which will increase prices for households and industrial users. Conversely, credit creation will also generate revenue for low-carbon energy suppliers, which will make low-carbon fuels and energy sources (e.g. electricity, renewable diesel) relatively less expensive in comparison. This will lead to decreased end-use demand for fossil fuels and increased end-use demand for lower carbon energy sources. To evaluate the impact of price effects that the Regulations could be expected to have on Canadian economic activity and GHG emissions, a macroeconomic analysis (or dynamic analysis) was completed using EC-PRO, the Department’s computable general equilibrium (CGE) model, and is presented as part of the distributional analysis of regulatory impacts.

Between 2022 and 2040, the cumulative domestic GHG emission reductions attributable to the proposed Regulations are estimated to be approximately 204 Mt CO₂e (about 18.0 Mt in 2030) at a net societal cost of about $30.8 billion. This analysis presents the benefits and costs to Canadian society as whole. The Regulations are also expected to increase fuel prices, so a fuel price analysis was conducted and is presented below. In addition, the direct impacts of the Regulations and effects from relative changes in energy prices are not uniformly distributed across society so the analysis has considered a range of distributional impacts, including the overall GDP and GHG impact, impacts on provinces and territories, impacts on sectors, as well as household and gender-based analysis plus (GBA+) impacts. Furthermore, distributional impacts are presented using 2030 as a representative year given that 2030 is the year in which the Regulations will reach full stringency.

Fuel price analysis

The Regulations are expected to increase production costs for primary suppliers, which will increase gasoline and diesel prices for households and freight transportation since they are the main consumers of these liquid fuels. Table 22 presents the share of liquid energy demand by broad sector category projected in 2030. The majority of gasoline demand is consumed by households and the majority of diesel demand is consumed by freight transportation and industry.

Table 22: Share of liquid energy (gasoline and diesel) demand by sector category in 2030
Sector category	Share of liquid energy demand (%)
Households	41
Freight transportation	40
Industry	11
Commercial	8
Electric utility generation	<1

Price impacts in the earlier years of the Regulations are expected to be minimal given the initial stringency in 2023 (at 3.5 gCO₂e/MJ CI reduction) that will be met with credits created from actions expected to occur in the baseline scenario (such as credits from supplying fuel or energy to advanced vehicle technologies and existing blending requirements), which will be banked in the initial years. As the stringency increases gradually over time to a 14 gCO₂e/MJ CI reduction in 2030, incremental price impacts will likely increase year by year as firms begin to invest in incremental credit creating projects.

Three scenarios of potential incremental price impacts in 2030 on gasoline and diesel are presented in Table 23, assuming that demand for energy remains constant (a partial-equilibrium analysis). There is no incremental cost to LFO and HFO as the fuel pools are no longer required to fulfil a CI requirement. However, blending in the fuel pools are expected in the central case, with the associated costs assumed to be absorbed in the gasoline and diesel fuel price impacts. One scenario represents a low-likelihood situation in which all credits are self-created and used by primary suppliers to meet their CI reduction requirement, and therefore credits will not go to the credit market for sale. To estimate this, the average cost to create a credit was used and is estimated at about $150 per credit in 2030. The average cost to create a credit was estimated by taking the credit creation cost for each pathway in 2030 and then multiplying that by the number of credits created for each pathway. Another scenario represents a low-likelihood situation in which all credits are created by voluntary parties and are sold into the credit market at market value. To estimate this, the marginal cost to create a credit was used and is estimated at $343 per credit in 2030.

These scenarios represent lower and upper bound estimates of the cost per credit (none or all of the credits are sold on the market). A more likely situation will be where some credits are sold in the credit market at market value and some are created and used by primary suppliers to meet their own annual reduction requirement. For example, it is expected that most credits from actions along the lifecycle will be self-created by primary suppliers and will not be sold on the credit market at market value, while most credits from supplying fuel or energy to advanced vehicle technologies will be created by voluntary parties and will go to market at market value. Credits from supplying low-carbon fuels are expected to be created via a combination of both voluntary parties and primary suppliers. These credits may not go to market if there is a contract in place between the voluntary parties producing low-carbon fuels and the primary suppliers.

With this in mind, a couple of simple scenarios are considered to establish a narrower range of estimates for the likely cost per credit. This suggests that the average cost will be within this range and a value of $250 is used to determine a central estimate of likely fuel cost increases attributable to the Regulations.

Table 23: Estimated range in incremental fuel price impacts in 2030 (cents per litre)
Note: this analysis does not account for increased low-carbon fuel use in the fuel pools.
Fuel pool	No credits go to market (All credits are self-created)	Some credits go to market (Some credits are self-created)	All credits go to market (No credits are self-created)
Gasoline pool	6	10	13
Diesel pool	7	12	16

The degree to which production cost increases results in price increases to consumers depends on several market factors, including distribution constraints, market share competition, refinery capacity and production, and fuel demand. Of the various factors contributing towards the fuel prices, the crude oil price has the highest variability. The Energy Information Administration estimates the single largest influence behind changing gasoline prices is the crude oil market, which is subject to speculation, price shocks, supply disruptions, and general uncertainty.^{footnote 83} For example, average gasoline prices in Canada from 2010 to 2019 have ranged from approximately 90 to 140 cents a litre.^{footnote 84} Gasoline prices experience volatility often related to fluctuations in the crude oil market, but gasoline is subject to its own supply and demand pressures. Cyclical trends such as seasonal changes in refining costs, production adjustments, and changes in demand contribute to gasoline price movements over a typical year.^{footnote 83} Therefore, while the Regulations may increase fuel prices, their anticipated impact on fuel prices is within the range of regular fuel price fluctuations.

EC-PRO modelling

A macroeconomic analysis of impacts on GDP and GHG emissions, impacts on provinces and territories, and impacts on sectors was modelled using EC-PRO, the Department’s computable general equilibrium (CGE) model of climate change policies. EC-PRO captures differences between provinces and territories and forecasts national impacts. EC-PRO simulates the response to the Regulations in Canada’s main economic sectors in each jurisdiction, and models the interactions between sectors, including interprovincial trade. It captures characteristics of provincial production and consumption patterns through a detailed supply-use table and links provinces and territories by means of bilateral trade. Each province and territory is explicitly represented as a region. The rest of the world is represented as import and export flows to Canadian provinces and territories, which are assumed to be price takers in international markets. The model incorporates information on energy use and combustion emissions from the Departmental Reference Case.

Impacts on GDP and GHG emissions

The Regulations will increase production costs for primary suppliers. Subject to the market considerations outlined above, it is likely that at least some of these costs will be passed on in the form of increased prices for liquid fuel consumers (i.e. households and industrial users). Credit creation will also generate revenue for low-carbon energy suppliers, which will make low-carbon fuels and energy sources (e.g. electricity, renewable diesel) relatively less expensive in comparison. On balance, these price effects are expected to lead to decreased end-use demand for fossil fuels and increased end-use demand for lower-carbon fuels and energy sources. To evaluate the direct impact of the Regulations as well as the effect of relative price changes on Canadian economic activity and GHG emissions, a macroeconomic analysis was completed using the EC-PRO model. As EC-PRO is a general equilibrium model, it captures direct and indirect impacts to all components of GDP. Modelling suggests that the Regulations will lead to a decrease in overall GDP of up to $9.0 billion (or up to 0.3% of total GDP) and GHG emission reductions of up to 26.6 Mt in 2030, assuming that all credits are sold in the credit market and are sold at the marginal cost per credit, and the fund is only partially accessed.

The Regulations will work in combination with other federal, provincial, and territorial climate change policies to create an incentive for firms to invest in innovative technologies and fuels by setting long-term, predictable and stringent targets. The broad range of compliance strategies allowed under the Regulations will also allow fossil fuel suppliers the flexibility to choose the lowest-cost compliance actions available. If the Regulations induce more long-term innovation and economies of scale than currently estimated, then the Regulations could result in lower costs and greater reductions, particularly over a longer time frame.

GDP impacts by province and territory

The costs associated with the Regulations will vary by region. Table 24 shows the breakdown of estimated GDP impacts due to the Regulations across Canada using EC-Pro.

Table 24: Distribution of estimated GDP impacts across regions in 2030
Province/territory	Millions of dollars	Percentage change (%)
British Columbia	(340)	<(0.1)
Alberta	(1,772)	(0.4)
Saskatchewan	(987)	(0.9)
Manitoba	(350)	(0.4)
Ontario	(2,855)	(0.3)
Quebec	(1,706)	(0.3)
New Brunswick	(255)	(0.6)
Nova Scotia	(378)	(0.7)
Prince Edward Island	(54)	(0.6)
Newfoundland and Labrador	(370)	(1.0)
Yukon	43	0.9
Northwest Territories	28	0.8
Nunavut	37	0.7

It is estimated that the Regulations will have a negligible GDP impact on British Columbia due to revenues generated from baseline blending credits attributed to the existing Renewable and Low Carbon Fuel Requirements Regulation and baseline credits from supplying fuel or energy to advanced vehicle technologies in the province. Alberta and Saskatchewan are also estimated to have GDP impacts since upstream oil sectors are largely located in these provinces requiring the credit obligations. These impacts are higher than in the modelling analysis presented in Canada Gazette, Part I. Two factors contribute towards this increase. Firstly, the higher CI stringency results in a larger reduction requirement on primary suppliers. Secondly, design and modelling changes are narrower in scope with regard to representative pathways included in the central case. While some projects that conserve hydrocarbon gases are eligible under the generic quantification method, this pathway is no longer included in the central case. It is expected that there are more CCS abatement possibilities in Alberta compared to Saskatchewan. Saskatchewan has relatively more emissions in light oil mining or heavy oil mining, where there is a lack of CCS modelling cost information. GDP impacts may be smaller in Saskatchewan should there be an uptake in CCS or other GHG emission reduction projects in the province.

Ontario and Quebec will have the largest absolute decrease in GDP given that they are the largest provinces by population and their aggregate fuel consumption is higher than in other provinces. However, relative to the size of their GDP, it is estimated that provinces in Atlantic Canada will be more negatively affected by the Regulations. This is largely because the Atlantic Provinces are estimated to have fewer opportunities to create credits from actions along the lifecycle of fuels (for example credit creating opportunities from CCS are unavailable due to inadequate geological storage). Furthermore, baseline EV and low-carbon fuel uptake in Atlantic Canada is low in comparison to other provinces. This lack of baseline credits affects Newfoundland and Labrador in particular given that the province does not have a blending requirement in place and it was exempt under the federal RFR. Furthermore, EC-Pro modelling was conducted utilizing an adjusted version of the 2021 Reference case which did include production from North Atlantic Refinery Limited Refinery’s Come by Chance refinery. The facility would have faced the reduction requirement under the Regulations. Given the refinery’s closure, the GDP impact in the province is expected to be smaller than modelled.

Ontario, Quebec, and Manitoba exhibit comparable estimated GDP impacts in scale. For all three provinces, credit creation from actions along the lifecycle of fuels is limited, with the supply of low-carbon fuels and baseline EV uptake creating the majority of credits.

Liquid fuels supplied to non-industrial remote communities are exempt under the Regulations. As a result, the model assumes that liquid fuels supplied to the territories will not be covered under the Regulations, but the territories will still have the ability to generate revenue from the creation of credits. In the model, credits are created in the territories via endogenous fuel switching to lower carbon energy sources. This results in a positive impact on GDP.

Impacts by sector

It is expected that the Regulations will increase production costs for primary suppliers (mostly oil refineries and upgraders). In turn, the resulting higher gasoline and diesel prices will increase costs for sectors that use these fuels in their production processes, which will result in changes to output. Table 25 presents the estimated percentage change in output by sector in 2030, assuming that all credits go to market and sell at the marginal cost per credit. Change in output reflects the increase or decrease in the output of finished products within a particular sector. In EC-PRO, sectors adapt to changing prices in order to maximize profit, and each sector is modelled as one representative firm per province or territory. Therefore, the results do not reflect the impacts on individual facilities. Based on these assumptions, it is estimated that the Regulations will have a negative impact on output for all sectors except for electricity generation. Uncertainty exists surrounding the extent to which fuel consumers will be able to fuel switch away from liquid fuels and make efficiency improvements to mitigate cost impacts and resulting output reductions.

Table 25: Cost as a percentage change in output by sector in 2030
Sector	Change in output (%)
Electricity generation	0.3
Oil sands upgraders	0.5
Services	(0.1)
Manufacturing and construction	(0.1)
Cement and other non-metallic minerals	(0.2)
Airline transportation	(0.2)
Mining (including coal)	(0.2)
Primary metals (including iron and steel, aluminum, and other)	(0.2)
Natural gas extraction, processing and distribution	(0.2)
Chemicals (including fertilizers)	(0.3)
Agriculture, forestry and lumber	(0.5)
Conventional oil extraction	(0.6)
Pulp and paper	(0.6)
Oil and gas pipelines	(0.8)
Primary oil sands and oil sands mining	(0.9)
In-situ oil sands	(0.9)
Oil refineries	(2.0)
Freight transportation (ground)	(2.1)

This modelling estimates that the Regulations will decrease output for in-situ oil sands (0.9%), oil refineries (2.0%), and freight transport (2.1%) the most. Oil refineries are primary suppliers under the Regulations and the majority of the gasoline and diesel they produce are supplied for domestic use. Therefore, the majority of their output is directly subject to the CI reduction requirements under the Regulations. A combination of low-carbon fuel uptake and price impacts on fuel cause a decrease in output for refineries. Since refined fossil fuel output decreases, the demand for bitumen also decreases. Freight output also decreases (2.1%) because liquid fuels represent a relatively large portion of the freight costs. Increased freight production costs are passed onto service users which results in decreased demand.

Oil sands upgraders are also primary suppliers under the Regulations; however, there is an estimated increase in product output for upgraders 0.5%. This is because most of the synthetic crude produced by upgraders is exported, and as such, is not covered by the Regulations. In addition, it is estimated that upgraders, and to varying degrees oil extraction sectors, will have more revenue-generating opportunities from the creation of credits for actions such as CCS and process improvements, in order to meet their annual CI reduction requirements.

Most of the other sectors presented in Table 25 are end users of gasoline and diesel and/or freight transportation service users and are not subject to the requirements under the Regulations. The magnitude of the estimated impact on these sectors is dependent on how much liquid fuel and freight transportation they consume, as well as the degree to which increased fuel costs are likely to lead to reduced demand for their products. As a result, it is estimated that these sectors will have small decreases in product output of 0.1% in the manufacturing and construction sector to 0.9% in the primary oil sands and oil sands mining sector.

Electricity generation has a positive output effect (0.3%) because the Regulations will create an incentive to switch from fossil fuels to electricity since it is generally less carbon intensive, depending on the region. The agriculture, forestry and lumber sector is estimated to have a negative output effect (0.5%) because low-carbon fuels used for blending are assumed to be imported. To the extent that the low-carbon fuels used for compliance with the Regulations are produced domestically, the impact on output will be lower or even positive.

Competitiveness impacts

Primary suppliers

Refineries, upgraders, and importers that supply gasoline and diesel (primary suppliers) will incur compliance costs in order to comply with the Regulations. Fossil fuel importers and producers are subjected to the same annual CI reduction requirement. Therefore, in the near term, refineries and importers will have the scope to increase product prices in order to mitigate increased production costs rather than to absorb them through lower profit margins. This will allow them to maintain competitiveness in the short run. However, over time, increases in gasoline and diesel prices will be expected to change consumption behaviour in Canada, reducing the overall demand for gasoline and diesel and their inputs (e.g. bitumen).

Upgraders will have limited flexibility to increase product prices to their customers in order to mitigate compliance costs. Prices for inputs (e.g. heavy oil and bitumen) are based on North American heavy oil benchmarks, leaving little scope for upgraders to influence the prices. However, upgraders primarily export the synthetic crude that they produce, so the impact on the sector is expected to be minimal given that exports are not covered under the Regulations. In addition, most of the companies that own upgraders also own refineries. These companies may be at more of an advantage under the Regulations than refining companies that do not own any upstream operations given that they will have more credit creating opportunities for actions along the lifecycle of fuels.

Compliance costs associated with the Regulations will likely be greater for firms with less ability to create compliance credits rather than acquiring them from third parties. These are likely to be firms with constrained access to capital, such as primary suppliers with lower levels of production, or limited access to credit creation opportunities. For these firms, additional compliance costs could affect their economic viability if there is insufficient time remaining in the life of a facility to recover the compliance costs. In certain cases, facilities may need to alter operations due to the Regulations.

It is possible, but unlikely, that firms may choose to increase exports of gasoline and diesel in order to avoid domestic CI reduction requirements under the Regulations. It is unlikely because all regulated fossil fuels under the Regulations are assigned the same baseline CI value, so there is no advantage to adjusting the mix of fuels sold domestically or exported based on differences in CI values. Furthermore, international demand for fossil fuel is exogenous and the Regulations will not spur an increase in demand for Canadian fossil fuel outside of Canada.

In response to potential financial and competitiveness impacts, several flexibilities have been included in the Regulations. For example, the broad range of compliance strategies provided for under the Regulations will allow primary suppliers to choose the lowest cost compliance actions available. In addition, the long-term nature of the Regulations and the gradual increase in the annual CI reduction requirement between 2023 and 2030 will allow time for investments to take place and will give investors the certainty needed to make longer-term investments in clean technologies, production facilities, and infrastructure.

Freight transportation sector

The freight transportation sector is an end user of gasoline and diesel, and will incur increased costs due to the Regulations as a result of gasoline and diesel price increases. As this sector is not trade-exposed and does not compete directly in international markets, it is expected that the freight transportation sector will offset any increased costs due to the Regulations by increasing freight transport service prices. As a result, sectors that use freight transportation services, such as mining for example, will incur increased costs from the Regulations. However, it is possible that some firms in the freight transportation sector may not be able to fully pass on increased costs and may need to absorb some of these costs, depending on market share competition in the regions in which they operate. As a result, additional compliance costs may require those firms to alter operations due to the Regulations.

Liquid fossil fuel end users and freight transportation service users

Some sectors that are gasoline and diesel end users or are freight transportation service users, such as mining and iron and steel, will experience increased costs as a result of the Regulations. However, the Regulations provide an exclusion for fuels used for generation of electricity in remote communities from CI reduction requirements, which would help mitigate some of the impacts. The output effects by sector are estimated to be low, even when using a low-likelihood scenario where all credits go to market at the marginal cost per credit (see Table 25). Therefore, it is unlikely that these increased costs will cause industry to move production to jurisdictions with lower carbon-related costs. Consequently, it is considered unlikely that the Regulations will result in “carbon leakage,” in which domestic production is displaced to a foreign location, with domestic GHG emissions “leaking” out of Canada to other jurisdictions.

Household and gender-based analysis plus (GBA+) impacts

The Regulations are estimated to increase the price of gasoline and diesel and a large portion of these liquid fuels are consumed by households. The Regulations will increase transportation fuel and it is estimated that increased household costs for gasoline and diesel could range from $2.2 to $5.1 billion, with a central estimate of $3.7 billion. Assuming 2.5 people per household on average in Canada and applying that to the 2030 population projection of 42.4 million, it is estimated that the Regulations will result in an average cost per household of $132 to $301 in 2030, with a central estimate of $220.^{footnote 85} However, these impacts will not be distributed equally across households. The average cost per household will depend on how much or what type of liquid fuel a household consumes.

It is expected that increases in transportation fuel expenses will disproportionately impact lower and middle-income households, as well as households currently experiencing energy poverty or those likely to experience energy poverty in the future.^{footnote 86} Moreover, according to Statistics Canada, single mothers are more likely to live in lower-income households, and may be more vulnerable to energy poverty and adverse impacts from increases to transportation.^{footnote 87}

Seniors living on fixed incomes may also face higher transportation costs resulting from the Regulations. This may be most acute for seniors living in the Atlantic provinces, where they account for a higher share of the total population compared to other Canadian provinces and are also more likely to experience some of the highest energy expenditures in Canada proportional to income.^{footnote 88,}^{footnote 89} It is possible that there could be other socio-economic groups that may have disproportionately lower income, may be at an increased vulnerability to energy poverty, or may be adversely affected by the Regulations. However, these groups may not be fully captured in this analysis due to lack of data availability, scarcity of research, or under-representation in available studies.

Household transportation

Households use gasoline and diesel primarily for passenger transportation, through personal vehicle ownership and public transportation. This will result in higher refuelling costs for owners of personal vehicles, and added costs to public transportation agencies, potentially resulting in higher fares. Using the increased gasoline price estimates from Table 23, it is estimated that increased costs could range from $76 to $174 per vehicle in 2030 for households that use gasoline-powered internal combustion engine vehicles, with a central estimate of $127 per vehicle.^{footnote 90} However, the overall impact on households will vary based on factors such as vehicle fuel type, geography, distances travelled by households and vehicle efficiency.

Low-income households may be disproportionately affected by the Regulations as they may incur higher transportation costs relative to their income.^{footnote 91,}^{footnote 92} Moreover, low-income households tend to have a lower ability to absorb higher fuel costs compared to high-income households. In addition, low-income households that rely on personal vehicle transportation may also have limited ability to switch to newer, cleaner or more fuel-efficient vehicles. For example, EVs (such as plug-in EVs, plug-in hybrid EVs, and hybrid EVs) are relatively newer technologies that tend to have greater upfront costs compared to internal combustion engine vehicles. Therefore, low-income households may continue to purchase cheaper automobile options (i.e. those with internal combustion engines) despite increased gasoline prices, though they may choose not to drive as much.^{footnote 92}

The Regulations will also affect households differently depending on geography and region. For instance, rural households are more likely to have higher rates of vehicle ownership, but they are also more likely to have less access to public transportation.^{footnote 93} For this reason, they may have limited opportunity to reduce their fuel consumption in response to higher gasoline prices. Similarly, Canadian households in the Atlantic Provinces spend a higher proportional amount of their expenditures on private transportation compared to all other provinces while also having some of the lowest average levels of disposable income.^{footnote 94} Therefore, the impact of increased gasoline prices may have a larger impact on households in the Atlantic Provinces compared to other areas.

The Regulations will increase the price of diesel fuel. Municipalities that rely on diesel-powered buses as part of their public transportation fleets may respond to this fuel price increase by raising transit fares. This will disproportionately impact lower-income households; a group more likely to use mass transit on a regular basis, and also more sensitive to transit fare increases.^{footnote 95,}^{footnote 96} However, impacts could be mitigated through discounted transit fares offered to lower-income households. An increase in fuel costs could also result in encouraging increased transit ridership, potentially generating additional revenue to offset the rising costs.^{footnote 97}

If electric bus uptake is higher than estimated in this analysis, this could also reduce the impact of fuel prices on transit authorities. As transit authorities shift towards replacing diesel powered fleets with electric buses, fuel consumption will decrease, and a variation in fuel price will have a smaller impact on operating expenditures. Furthermore, transit authorities could create credits under the Regulations by implementing electric bus fleets. As a result, cost impacts on transit authorities could be mitigated through sale of credits.

Impacts on remote communities

The Regulations provide an exclusion for liquid fossil fuels supplied to non-industrial remote communities in order to minimize the potential for disproportionate impacts to occur. The Regulations provide an exclusion for fuels used for generation of electricity in remote communities from CI reduction requirements, which would also help mitigate some of the impacts.

Employment impacts

It is estimated that the Regulations could create job opportunities in sectors that may benefit from generating credit revenue (e.g. clean technology), and lost job opportunities in other sectors that are primary suppliers or that use liquid fuels (e.g. oil and gas). A full employment analysis has not been conducted because GBA+ impacts will depend on the actual compliance strategies chosen and will depend on the characteristics of the specific populations employed at firms or facilities that may be affected. For example, it is assumed in the analysis that increased demand for low-carbon fuels will be met by imports. However, if low-carbon fuels are supplied domestically, this could result in positive employment impacts in low-carbon fuel sectors. Young and middle-aged men will be at the greatest advantage to benefit from employment opportunities within these sectors.^{footnote 98,}^{footnote 99}

Job opportunities in the oil and gas, or freight transport sectors are expected to be negatively impacted given that the Regulations will increase production costs for these sectors and will decrease demand for fossil fuel products. Canada’s oil refining sector as an example, employs a high proportion of middle-aged men compared to the average working-age population. This group may face an increased risk of job scarcity due to the Regulations.^{footnote 100} When searching for new employment, older workers in Canada (especially those aged between 55 and 64) face unique barriers including ageism; lack of education and access to training; difficulty finding and applying for jobs; health issues, work-life balance issues, and lack of workplace accommodations.^{footnote 101,}^{footnote 102,}^{footnote 103} Facilities within rural communities may also be adversely impacted. Rural facilities often contribute to rural economies by providing high-paying salaries, municipal tax proceeds, and infrastructure investments. As such, reductions in industrial activity, salaries, and jobs could potentially negatively affect economic activity and population retention in rural communities.

Environmental impacts

A consequence of climate change is the increased frequency, intensity and/or duration of extreme weather events, which increases risks for vulnerable populations such as children, seniors, low-income earners and the homeless, as well as communities in areas exposed to natural hazards. These impacts include increased demands on health care services, disruption of social networks, damage to, or unavailability of, housing, shelter and other physical infrastructure (e.g. hospitals, grocery stores, telecommunications).^{footnote 104} Incremental damages incurred as a result of an increase in GHG emissions are considered to be distributed globally. There are two unique aspects to climate change: (1) it involves a global externality, where emissions anywhere in the world contribute to global damages; and (2) the only way to effectively address climate change is through global action. The Regulations, in combination with actions in the ERP, would help to minimize the impacts of climate change globally. These measures could also minimize the impacts of climate change on potentially vulnerable groups in Canada, and contribute to a resilient Canadian economy.

Small business lens

Analysis under the small business lens concluded that the Regulations will not directly impact Canadian small businesses. No mandatory regulated parties are considered small businesses, and no voluntary participants are expected to be small businesses. Furthermore, as enabled under subsection 140(3) of CEPA, primary suppliers that produce or import less than 400 m³ of liquid fossil fuel per year are not subject to the requirements of the Regulations.

One-for-one rule

The one-for-one rule applies since there is a net incremental increase in administrative burden on business. The Regulations will result in a new regulatory title and will be considered an “IN” under the Government of Canada’s one-for-one rule, meaning that the Regulations will increase administrative burden costs on businesses and introduce a new regulation. As the Regulations will also incorporate the renewable fuel volumetric requirements set out under the federal RFR, this new regulatory title will be offset by the repeal (an “OUT”) of the existing federal RFR. This will result in a net neutral impact on regulatory titles as per the Government of Canada’s one-for-one rule.

Under the Regulations, only primary suppliers will be subject to mandatory administrative requirements to submit compliance reports. Other parties, such as low-CI fuel producers and importers do not need compliance credits to comply with the Regulations, they have the option to create compliance credits and participate in the credit market, which will incur administrative costs. For the purpose of this one-for-one analysis, any administrative burden associated with credit creation is estimated and included regardless of source. Some primary suppliers may also serve as voluntary credit creators whereby they may, for example, produce or import low-CI fuels. As such, there may be some overlap between primary suppliers and voluntary credit creators.

The administrative costs incurred by primary suppliers that will result from implementation of the Regulations are primarily tied to learning about the administrative requirements of the Regulations, registering, the ongoing record-keeping requirements, reporting, and third-party verification of reports. The Regulations will require primary suppliers to submit annual compliance reports and to have them verified by third parties. Preparing and submitting the report is estimated to take 32 hours per company per year, and verification by third parties is expected to take roughly 300 hours per company per year. For legal contracting, it is estimated that it will take about four hours on average at a frequency of eight times per company per year. Primary suppliers will also be required to submit a one-time registration report to the Department to register as a primary supplier under the Regulations. In addition, management, scientists, engineers, analysts, accountants, lawyers and auditors will be required to learn about the Regulations. It is assumed that it will take about six hours per company to register and between an average of 16 to 40 hours per company to learn about the administrative requirements of the Regulations.

In the analysis for the proposed Regulations, administrative burden was only calculated for obligated parties and costs imposed on voluntary credit creators were not considered. This approach was taken due to the assumption that non-obligated parties would only enter the credit market when such an action would be profitable. For the final Regulations, voluntary credit creators have been included in the one-for-one analysis to demonstrate that consideration has been taken to limit regulatory burden on businesses, allowing for efficient creation of credits for the credit market.

Non-regulated entities who participate in the CFR credit market through voluntary credit creation will be subject to administrative requirements and thus will incur some costs associated with these actions. Administrative costs are primarily linked to learning about the administrative requirements of the Regulations, record-keeping, registration, application, reporting, and verification. The Department expects the following industries may find it beneficial to willingly participate in the CFR credit market: Low-CI fuel producers and importers, companies owning natural gas fuelling stations, owners or operators of injection sites for CCS, network operators for public or residential EV charging, site hosts for EV charging, and voluntary credit creators for emerging technology. In total, the Department estimates there could be approximately 111 voluntary credit creators participating in the CFR credit market.

The Regulations will also incorporate the existing volumetric requirements that are in the federal RFR, which currently require an average 5% renewable fuel content in gasoline and 2% renewable fuel content in diesel fuel and heating distillate oil. Incorporating RFR requirements into the Regulations and repealing the RFR itself will not impose new administrative burden on businesses (i.e. the existing RFR requirements will be carried over to the Regulations without change), but this will decrease administrative burden as explained below.

The last compliance period for the RFR will be 2022. The final reporting period will be in 2023, the final roll-out period in 2024, and the RFR will be repealed in 2024. As of 2023, RFR stakeholders (e.g. fossil fuel and renewable fuel producers and importers) will no longer be required to create or maintain new records and submit compliance unit account books. In addition, they will no longer be required to submit reports for Schedule 4 (Annual Report from a Primary Supplier), Schedule 5 (Annual Report from a Participant), and Schedule 7 (Annual Report from a Renewable Fuel Producer or Importer), or complete Schedule 3 (Auditor’s Report) auditing as of 2024.

The one-for-one analysis estimates that 30 primary suppliers obligated under the Regulations will incur incremental costs in addition to cost savings from the repeal of the RFR. The net annualized administrative costs for primary suppliers is estimated to be $228,000, or $7,500 per business.^{footnote 105} Businesses that were regulated under the RFR but will not be mandatory regulatees under the Regulations will see net cost savings estimated to be $105,000, or $2,500 per business.^{footnote 106} Total annualized administrative costs for voluntary credit creators are estimated to be $1.4 million, or $12,500 per business.^{footnote 107} The costs incurred by voluntary credit creators are expected to be offset by selling credits on the market, leading voluntary credit creators to benefit net of costs from participation in the CFR credit market. Over a 10-year timeframe (2022 to 2031), 30 primary suppliers and an estimated 111 voluntary regulatees will incur net annualized administrative costs estimated to be $1.5 million annually, or $11,000 per business.^{footnote 108}

Regulatory cooperation and alignment

Canada is working in partnership with the international community to implement the Paris Agreement, to support the goal of limiting temperature rise this century to well below 2°C and pursing efforts to limit the temperature increase to 1.5°C. As part of its commitments made under the Paris Agreement, Canada pledged to reduce national GHG emissions by 40–45% below 2005 levels by 2030. The Government of Canada has also committed to achieving net-zero emissions by 2050. The Regulations will contribute to these GHG reduction targets.

International

No other jurisdictions have national regulations that are similar to the Regulations. The EU has a similar policy in place called the Fuel Quality Directive that requires fuel suppliers to reduce lifecycle GHG emissions from fuels by up to 10% by 2020. The Fuel Quality Directive works in tandem with the EU Renewable Energy Directive, which stipulates that the share of biofuels in the transportation sector should be 10% (by energy content) for each member country by 2020. Some aspects of the Regulations will align. For example, the Regulations will have similar sustainability criteria as the EU’s Fuel Quality Directive in order to mitigate indirect land-use change impacts. However, despite similar objectives, the overall policy approach will differ from the EU.

United States

The United States does not have a national regulation that targets the lifecycle emissions of fossil fuel production. However, it does have the Renewable Fuel Standard (RFS), which requires a minimum volume of renewable fuel content in transportation fuel sold domestically.^{footnote 109} The Regulations do not have any linkage to the RFS, as the two programs will be different in GHG reduction strategies. The Regulations provide an incentive to increase low-carbon fuel blending; however, the obligated parties will determine lifecycle carbon-intensity strategies.

California and Oregon have also enacted regulations that target CI reductions. California’s Low Carbon Fuel Standard (LCFS) was enacted in 2007, with a target of reducing the CI of transportation fuels at least 10% by 2020. In 2018, the California Air Resource Board approved amendments to the regulation, which requires fuel suppliers to reduce the CI of transportation fuels (fossil fuels and those replacing them) they supply by at least 20% by 2030, from a 2010 baseline. Oregon’s Clean Fuel Program took effect in 2016 and requires a reduction in the annual average CI of Oregon’s transportation fuels (gasoline and diesel) by 10% from the 2015 level by 2025. It has similar objectives and approaches to California’s Low Carbon Fuel Standard and the Regulations.

On June 26, 2019, the Minister of Environment and the Chair of the California Air Resources Board signed a new cooperation agreement to advance clean transportation. The agreement commits Canada and California to work together on their respective regulations to cut down on GHG pollution. Canada and California also committed to share best practices and technical information about regulating cleaner fuels, building on California’s Low Carbon Fuel Standard, Canada is also developing the Regulations as part of this initiative.^{footnote 110}

Despite similar objectives and approaches, the Regulations have several design elements specific to Canada. One such variation is the accounting of land use change while determining lifecycle CI of fuels. The California and Oregon regimes also differ partly because the Regulations are targeting fuels not limited to transportation. The Regulations and the California and Oregon programs have no interactions in the credit trading system.

Provinces and territories

The PCF was adopted by the Prime Minister and most First Ministers in December 2016. It sets out a collective plan to reduce GHG emissions, grow the economy and adapt to climate change. The Regulations will be implemented as part of the PCF.

The Regulations aim to ensure compatibility with other federal and provincial policies such as federal and provincial carbon pricing systems, and BC’s RLCFRR and were designed with input from provincial and territorial jurisdictions as well as other federal programs to align as best possible with evolving climate change objectives to provide investment signals that are consistent. The Regulations are not anticipated to cause any barriers to interprovincial trade of low-carbon fuels or fossil fuels, given the national scope of the regulations and the compatibility with provincial systems.

Participants can create and bank credits for actions that include current federal and provincial renewable fuel regulatory requirements and BC’s RLCFRR and were designed with input from provincial and territorial jurisdictions as well as other federal programs to align as best possible with evolving climate change objectives to provide investment signals that are consistent. The Regulations are not anticipated to cause any barriers to interprovincial trade of low-carbon fuels or fossil fuels, given the national scope of the regulations and the compatibility with provincial systems. For GHG emission reduction projects, the Regulations recognize the following projects that reduce the CI of fossil fuels as eligible for credit creation:

a project that enables the creation of credits under federal, provincial or territorial carbon pollution pricing systems; and
a project that meets the criteria for reducing the CI of fossil fuel throughout its lifecycle (Compliance Category 1) and that creates credits under BC’s RLCFRR, such as co-processing biocrudes at a refinery.

The Regulations allow for credit creation opportunities, even if a given project generates credits in another program (e.g. federal or provincial offset programs). However, it is important to note that different programs may decide not to provide credits for the same actions. Stakeholders seeking clarity should contact the programs they are interested in to determine if CFS credit creation will make a project ineligible for that particular program.

Quantification methods developed for credits in Compliance Category 1 are available and will be maintained by the Department. New quantification methods will be developed by a team of technical experts including departmental representatives and reviewed by a broader consultative committee that includes stakeholders in industry, academia, other technical experts, etc. The development of new methodologies will take into consideration existing emission reduction accounting methodologies or offset protocols in other jurisdictions including offset protocols in provinces and territories. In development of the quantification methods, the Department will consider alignment of the CFS quantification methods with offset protocols of other jurisdictions; however, it is expected that the quantification approaches will differ on a national level when compared to provincial or territorial specific quantification methods. The Minister will make the final determination on the addition of any new quantification methods, after having consulted the broader committee of technical experts.

Rationale

GHGs are primary contributors to climate change. The extraction, processing and combustion of fossil fuels is one of the largest sources of GHG emissions in Canada. Canada now intends to reduce GHG emissions by 40–45% below 2005 levels by 2030 and achieve the goal of net-zero emissions by 2050. Canada also made a commitment with provinces and territories to reduce GHGs under the PCF. To achieve these goals, a number of GHG reduction measures have been implemented or proposed, including the Regulations.

The Regulations require liquid fossil fuel primary suppliers (i.e. producers and importers) to reduce the CI of the gasoline and diesel they produce and import in Canada by 14 gCO₂e/MJ from 2016 intensity levels by 2030. The Regulations are intended to be a flexible, performance-based policy tool that reduces the CI of liquid fossil fuels supplied in Canada. The Regulations incorporate, but also improve upon the federal RFR by allowing more compliance flexibility and by incentivizing renewable and other clean fuels with the lowest CI. The Regulations are also complementary to carbon pricing as they provide an additional incentive to reduce GHG emissions by reducing the CI of liquid fuels, which are primarily used in the transportation sector, thereby driving reduced emissions from transportation beyond what will be achieved by carbon pricing alone.

Since February 2017, the Department has held extensive consultation sessions with stakeholders and provincial partners on the Regulations. Participation from industry stakeholders included fossil fuel producers and suppliers, low-carbon fuel producers and suppliers, emission-intensive and trade-exposed (EITE) sectors, and various industry associations. Participation from non-industry stakeholders included provinces, territories, ENGOs and associations representing Indigenous Peoples. Stakeholders expressed a diverse range of views prior to prepublication of the Regulations. ENGOs and stakeholders in the low-carbon energy sectors have indicated support for the Regulations while provincial governments and stakeholders in the oil and gas sector have raised concerns about the costs of compliance. The Department has made a number of changes to the proposal in response to feedback received.

The Regulations are made under the Fuels Division in Part 7 of CEPA 1999. Consistent with the requirements of this Division, the Governor in Council is of the opinion that they will make a significant contribution to the prevention of, or reduction in, air pollution. Cumulative GHG emission reductions attributable to the Regulations are estimated to range, over the period of 2022 and 2040, from 151 to 267 megatonnes of carbon dioxide equivalent (Mt CO₂e), with a central estimate of approximately 204 Mt.

To achieve these GHG emission reductions, it is estimated that the Regulations will result in societal costs that range from $22.6 to $46.0 billion, with a central estimate of $30.7 billion. Therefore, the GHG emission reductions will be achieved at an estimated societal cost per tonne between $111 to $186, with a central estimate of $151. To evaluate the central case results, a break-even analysis was conducted that compares the societal cost per tonne of the Regulations to the value of the social cost of carbon (SCC) in 2021 (estimated at $52/tCO₂) as per TBS guidance, and more recently published estimates of the SCC value in 2022, found in the academic literature ranging between $57 and $443/tCO₂. The Department’s current SCC has not been updated since 2013 and it is reasonable to conclude, looking at the key factors driving increases in more recently published academic estimates of the SCC, that an updated departmental SCC will result in a value that is higher than $52/tCO₂ in 2021. Based on a peer review and using the range of SCC estimates in the academic literature, it is reasonable to conclude that the GHG benefits of the Regulations will be greater than its costs.

The Regulations will increase production costs for primary suppliers, which will increase prices for liquid fuel consumers, households and industrial users. Credit creation will also generate revenue for low-carbon energy suppliers, which will make low carbon energy sources such as electricity less expensive in comparison. This will lead to decreased end-use demand for fossil fuels and increased end-use demand for lower carbon energy sources, thereby reducing national GHG emissions. To evaluate the impact of price effects due to the Regulations on Canadian economic activity and GHG emissions, a macroeconomic analysis was completed. When price effects are taken into account, in 2030, it is estimated that the Regulations will result in an overall GDP decrease of up to $9.0 billion (or up to 0.3% of total GDP) while reducing up to 26.6 Mt of GHG emissions, using an upper bound scenario where all credits are sold at the marginal cost per credit.

The Regulations work in combination with other federal, provincial, and territorial climate change policies to create an incentive for firms to invest in innovative technologies and fuels by setting long-term, predictable and stringent targets. Moreover, the long-term nature of the Regulations and the increase in the CI reduction requirement between 2023 and 2030 will allow time for investment to take place and may give investors the certainty needed to make investments in clean technologies, production facilities, and infrastructure required for longer-term decarbonization. The broad range of compliance strategies allowed under the Regulations provide flexibility to fossil fuel suppliers in choosing the lowest cost compliance actions available. If the Regulations induce more long-term innovation and economies of scale than currently estimated, they could result in lower costs and greater benefits, particularly over a longer time frame.

In addition, many Canadians view climate change as a global issue that requires Canada’s leadership to encourage other countries to participate in collective action to exceed the Paris Agreement’s central objective to limit global temperatures to well below 2 °C and pursue efforts to limit it to 1.5 °C, in addition to achieving the goal of net-zero emissions by 2050. Canada’s 2030 Paris commitment and net-zero 2050 goal require multiple policies, including the Regulations. If the Regulations are not implemented, then a policy alternative will need to be identified that could achieve the same amount of GHG emission reductions in order for Canada to exceed its 2030 commitment and achieve its 2050 goal.

Strategic environmental assessment

The Regulations have been developed under the PCF. A strategic environmental assessment (SEA) was completed for this framework in 2016.^{footnote 111} The SEA concluded that proposals under the framework will reduce GHG emissions and are in line with the 2016–2019 Federal Sustainable Development Strategy (FSDS) goal of effective action on climate change.^{footnote 112}

Implementation, compliance and enforcement, and service standards

Credit creation may be eligible upon registration of the Regulations. Reduction requirements for gasoline and diesel will begin for primary suppliers in July 2023. The Department will proactively communicate with known primary suppliers and potential voluntary credit creators, as well as industry associations for these sectors, to ensure a maximum number of potential participants are aware of the publication of the Regulations as well as relevant reporting requirements and deadlines.

Implementation and compliance

Implementation will start once the Regulations are registered and continue throughout the life of the program, evolving to adapt to changing markets and technologies. A rigorous compliance verification process, relying on reports and records, will be in place to monitor creation of compliance credits, annual reduction requirements and the credit trading system. Compliance activities are targeted at raising awareness and assisting the regulated community in achieving a high level of overall compliance as early as possible during the regulatory implementation process. Significant client services are required to develop compliance promotion material and respond to inquiries. In addition, the requirements set out in the Regulations are designed to be evergreen and adapt quickly to changing markets and technologies through the quantification methods and the Fuel LCA Model, which are outside the Regulations and do not require a regulatory amendment to change.

Outreach for regulated parties

Engagement will continue and need to remain responsive throughout implementation, especially in initial years as regulated parties register under the Regulations and require guidance. This would include responses to inquiries and regular compliance promotion activities (e.g. information sessions, workshops and training) to ensure that the requirements of the Regulations are well understood. Compliance promotion information such as web content, guidance material and frequently asked questions (FAQs) will be developed.

Development and review of quantification methods for GHG emission reduction projects

New quantification methods will be developed as new technologies are adopted and new project types are carried on in the oil and gas sector. The quantification methods are developed by the Department or a team of technical experts which includes departmental representatives. The development process involves consultations with stakeholders in industry, academia, provinces and other technical experts. Existing quantification methods may be reviewed when a project type is no longer considered additional, including when new legislation is implemented or existing legislation is amended impacting activities associated with the quantification methods.

Development and implementation of an online platform for reporting instruments

The Clean Fuel Regulations Credit and Tracking (CATS) is the IT system underpinning the Regulations. The system will consist of the following components: registration of all regulated parties, applications for projects and CI values, reporting systems for all regulated parties and third-party verification bodies, and facilitation of the credit and tracking system. Trainings on CFR CATS will be organized for regulated parties.

Fuel LCA Model

The Government of Canada Fuel Life Cycle Assessment (LCA) Model, developed by the Department, supports the implementation of the Regulations. The Fuel LCA Model is used in all three compliance categories to determine facility-specific CI values for low-CI fuels, material inputs and energy sources. A Stakeholder Technical Advisory Committee (STAC) provides advice and support to the Department via technical recommendations pertaining to the ongoing advancement and maintenance of the Fuel LCA Model. The STAC is composed of members from industry, academia, the Government of Canada, and ENGOs that have expertise in life cycle inventory, life cycle impact assessment or GHG quantification.

Land use and biodiversity criteria

Reviews of applications for legislative recognition from international jurisdictions on land use and biodiversity criteria will take place, as well as monitoring and reviewing legislative frameworks and sustainability of biofuel feedstocks to determine their ongoing eligibility for credit creation.

Review and approval of applications and quarterly and annual reports

Reports and applications will be reviewed as they are received to ensure compliance with the Regulations. The review of reports and applications will inform compliance promotion activities and these activities would be adjusted according to compliance analyses or if unforeseen compliance challenges arise. As the regulated community becomes more familiar with the requirements of the Regulations, compliance promotion activities are expected to decline to a maintenance level.

Quality assurance program for third party verification and certification program

The Regulations require applications and reports to be verified by a third party. Regulated parties will be required to obtain a report from an independent, accredited third-party verification body stating whether the information submitted is complete, compliant with the requirements of the Regulations, and credits and obligations are accurate and without material error. An accreditation program for third-party verifiers is being developed via collaborative work with accreditation bodies.

Review of the Regulations

Given the continually evolving market dynamics/credit creation opportunities, the Department will monitor and review market conditions on an ongoing basis. A review of the Regulations will be undertaken, per the Department’s regular practice and in line with the Cabinet Directive on Regulation. This review will conclude five years after the Regulations come into force, and will include a review of provisions on CI limits and credit creation opportunities.

Enforcement

As the Regulations are made under CEPA, enforcement officers would, when verifying compliance, apply the Compliance and Enforcement Policy (the Policy) for CEPA. The Policy sets out the range of possible enforcement responses to alleged violations. If an enforcement officer discovers an alleged violation following an inspection or investigation, the officer would choose the appropriate enforcement action based on the Policy. The Regulations also make related amendments to the Environmental Violations Administrative Monetary Penalties Regulations (EVAMPR). This will enable enforcement officers to issue an administrative monetary penalty (AMP) for certain violations under the Regulations. AMPs are penalties designed to create a financial disincentive to non-compliance with designated legislative requirements and to supplement existing enforcement measures. EVAMPR also specifies the method used to calculate the amount of the AMP, including baseline penalty amounts for different types of violations and violators, and aggravating factors, that, if applicable, may increase the amount of the penalty.

Contacts

Paola Mellow
Executive Director
Low Carbon Fuels Division
Carbon Markets Bureau
Environmental Protection Branch
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: cfsncp@ec.gc.ca

Matthew Watkinson
Director
Regulatory Analysis and Valuation Division
Economic Analysis Directorate
Strategic Policy Branch
Environment and Climate Change Canada
200 Sacré-Cœur Boulevard
Gatineau, Quebec
K1A 0H3
Email: ravd.darv@ec.gc.ca

Footnotes

Footnote a

S.C. 2004, c. 15, s. 31

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Footnote b

S.C. 1999, c. 33

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Footnote c

S.C. 2008, c. 31, s. 2

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Footnote d

S.C. 2009, c. 14, s. 126

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Footnote 1

SOR/2010-189

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Footnote 2

SOR/2017-109

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Footnote 3

Environment and Climate Change Canada (ECCC), Canada’s 2020 National Inventory Report.

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Footnote 4

Environment and Climate Change Canada (ECCC), Canada’s Fourth Biennial Report on Climate Change (PDF).

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Footnote 5

Environment and Climate Change Canada (ECCC), Facts on Climate Change.

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Footnote 6

More information is available in Canada’s INDC Submission to the UNFCCC (2015) [PDF] (PDF).

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Footnote 7

Pan-Canadian Framework on Clean Growth and Climate Change.

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Footnote 8

These documents are available on the page: Government of Canada announcement regarding the development of a clean fuel standard

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Footnote 9

These documents are available on the Clean Fuel Standard webpage. Further details on these documents and stakeholder responses are included in the “Consultation” section.

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Footnote 10

Proposed Clean Fuel Regulations: Canada Gazette, Part 1, Volume 154, Number 51

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Footnote 11

A Healthy Environment and a Healthy Economy, Canada’s Strengthened Climate Plan

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Footnote 12

Clean Fuel Standard: Discussion Paper (2017).

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Footnote 13

For more information, refer to the Renewable Fuels Regulations.

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Footnote 14

Renewable Fuel Standard Program

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Footnote 15

Renewable Fuel Standard Program: Standards for 2020 and Biomass-Based Diesel Volume for 2021 and Other Changes (PDF)

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Footnote 16

Renewable and Low Carbon Fuel Requirements

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Footnote 17

BC-LCFS Requirements

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Footnote 18

CleanBC Plan (PDF)

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Footnote 19

California Low Carbon Fuel Standard

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Footnote 20

Ricardo. (2018). California Low Carbon Fuel Standard: Rethinking Decarbonisation Incentives – Policy Case Studies (PDF)

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Footnote 21

Oregon Clean Fuels Program

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Footnote 22

European Commission Fuel Quality Directive (PDF)

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Footnote 23

European Commission Renewable Energy Directive

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Footnote 24

Kent Group LTD. 2016 Report on “Canada’s Downstream Logistical Infrastructure: Refining, Biofuel Plants, Pipelines, Terminals, Bulk Plants & Cardlocks.”

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Footnote 25

The liquid class credit reference CI value is the average CI for all liquid fuels supplied in Canada in 2016 minus the CI reduction requirement for all liquid fuels for a given compliance year.

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Footnote 26

The TBS Canadian Cost-Benefit Analysis Guide can be found on the Government of Canada website on the Cabinet Directive on Regulations: Policies, guidance and tools.

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Footnote 27

For more information refer to the Government of Canada’s greenhouse gas emissions projections website as well as Canada’s 2030 Emissions Reduction Plan (PDF).

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Footnote 28

An EV LDV modelling was conducted prior to the 2030 Target of 60% was established. The modelling assumed a 50% sales target by 2030.

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Footnote 29

For more information refer to the CER’s publication on Canada’s Energy Future.

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Footnote 30

Economic projections (including exchange rates and inflation) to 2023 are calibrated to Finance Canada’s February 2019 Budget Fiscal Outlook and economic projections between 2024 and 2030 are based on Finance Canada’s long-term projections.

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Footnote 31

For more information, refer to the website for the Government of Canada’s Greenhouse Gas Emissions Inventory.

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Footnote 32

Irlam, L., (2017). Global CCS Institute, Global Costs of Carbon Capture and Storage, 2017 Update (PDF).

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Footnote 33

For more information, please refer to the Government of Canada webpage on the Greenhouse Gas Reporting Program (GHGRP) - Facility Greenhouse Gas (GHG) Data.

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Footnote 34

Sources used include the following: Massachusetts Institute of Technology Carbon Capture and Sequestration Database; the ZERO CO2 CCS database; the Irlam, L., (2017). Global CCS Institute, Global Costs of Carbon Capture and Storage, 2017 Update (PDF); Price, J. (2014). Effectiveness of Financial Incentives for CCS. Bluewave Resources, LLC. (PDF); the Alberta government publications webpage on completed/announced CCS projects; NRCan publications on completed/announced CCS projects; the U.S. Office of Fossil Energy website; and various company websites.

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Footnote 35

Assumption based on Canada’s Oil Sands Innovation Alliance (COSIA), Sage Creek Consulting, and David Butler and Associates (2017). Oil Sands CO2 Pipeline Network Study (PDF). The study finds that operating and maintenance costs for a given year are generally expressed as 3–5% of the installed capital costs. This analysis assumes an average of 4%.

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Footnote 36

A diesel substitute produced from vegetable oils or waste residues made by an esterification process, also called “fatty acid methyl esters” (FAME).

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Footnote 37

A diesel substitute produced from vegetable oils or waste residues made by a hydrotreating process, also called “hydrotreated vegetable oil” (HVO) or “renewable diesel.”

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Footnote 38

U.S. Environmental Protection Agency, Fuels Registration, Reporting, and Compliance Help. E15 Fuel Registration.

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Footnote 39

For more information, refer to NRCan’s website on biodiesel market acceptance.

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Footnote 40

For more information, refer to NRCan’s website on biodiesel.

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Footnote 41

Neste Corporation (2016). Neste Renewable Diesel Handbook (PDF).

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Footnote 42

NRCan study (2016), Alternative Fuels in Emerging Applications.

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Footnote 43

USDA (2017). Canada: Biofuels Annual 2017 GAIN Report. Foreign Agricultural Service.

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Footnote 44

European Commission Sub Group on Advanced Biofuels (2017). Final Report: Building up the future, cost of biofuel. Sustainable Transportation Forum.

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Footnote 45

U.S. Department of Agriculture (USDA) (2017). Global Agricultural Information Network (GAIN) Report: Canada-Biofuels Annual-2017.

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Footnote 46

U.S. Energy Information Administration. Annual Energy Outlook 2018, Table: Petroleum and Other Liquids Supply and Disposition. Independent Statistics and Analysis.

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Footnote 47

U.S. Energy Information Administration. Total Energy Data: Annual Energy Review. Independent Statistics and Analysis.

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Footnote 48

Methodology to estimate the interim baseline CI values for liquid fuels, Environment and Climate change Canada, 2018. Report available upon request.

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Footnote 49

CARB LCFS Pathway Certified Carbon Intensities

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Footnote 50

Kent group LTD. 2016 Report on “Canada’s Downstream Logistical Infrastructure: Refining, Biofuel Plants, Pipelines, Terminals, Bulk Plants & Cardlocks (PDF).”

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Footnote 51

Information on the costs per site was obtained through stakeholder consultations.

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Footnote 52

Based on consultations with stakeholders

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Footnote 53

U.S. Department of Agriculture, U.S. Bioenergy Statistics: Prices. Table 15—Fuel ethanol, corn, and gasoline prices, by marketing year and Table 17—Biodiesel and diesel prices

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Footnote 54

Kent Group Petroleum Price Data on fossil fuel price margins.

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Footnote 55

Data sources from the literature review include the Sub Group on Advanced Biofuels – Sustainable Transportation Forum and the NRCan Study of Hydrogenation Derived Renewable Diesel as a Renewable Fuel Option in North America.

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Footnote 56

A review of potential refinery conversions was examined as a potential pathway for domestic HDRD production, with Total’s La Mede facility acting as a case study.

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Footnote 57

American Petroleum Institute, “Ethanol, Biofuels, and Pipeline Transportation (PDF).”

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Footnote 58

Based on the estimate used for the Renewable Fuels Regulations.

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Footnote 59

Navius Research (2019). Biofuels in Canada 2019: Tracking biofuel consumption, feedstocks and avoided greenhouse gas emissions.

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Footnote 60

NRCan study (2018) on the Deployment of Mid-level Ethanol Blends.

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Footnote 61

U.S. Department of Energy, Alternative Fuels Data Center: Biodiesel Benefits and Considerations.

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Footnote 62

This assumption is based on stakeholder consultation comments that 5 to 10% of EV chargers in Canada have metered charging data capabilities. This analysis assumes an average of that range of 7.5%.

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Footnote 63

“Mature technologies” are defined as technologies where the scientific background is well understood and they have been in use for a long enough period such that most of its initial liabilities and problems have been removed or reduced by further development.

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Footnote 64

For more information, refer to ECCC’s website on Air Quality.

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Footnote 65

For more information, refer to ECCC’s website on Air Pollutants Overview.

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Footnote 66

For more information on air pollutant emissions regulations and measures, refer to Canada’s Air Pollutant Emissions Inventory Report: 2020.

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Footnote 67

Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector).

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Footnote 68

Health Canada study (2010) on the Health Risks and Benefits Associated with the Use of 10% Ethanol-blended Gasoline in Canada.

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Footnote 69

Health Canada study (2012) on the Human Health Risk Assessment for Biodiesel Production, Distribution and Use in Canada.

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Footnote 70

In the “One-for-one rule” section of the Regulatory Impact Analysis Statement (RIAS), these costs are also annualized at $302,700 in 2012 dollars over a 10-year period (2021 to 2031) using a 7% discount rate as per the Red Tape Reduction Regulations.

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Footnote 71

Further information can be found in the Technical Update to Environment and Climate Change Canada’s Social Cost of Greenhouse Gas Estimates (PDF).

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Footnote 72

For further information, see the Policy on Cost-Benefit Analysis published by the Treasury Board of Canada Secretariat.

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Footnote 73

With the exception of the Department’s current SCC values, all SCC estimates retrieved from the literature have been first adjusted to 2021 US dollars using the US GDP deflator before being converted to Canadian dollars using the 2021 annual average market exchange rate retrieved from the Departmental Reference Case.

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Footnote 74

Nordhaus, W. D. (2017). Revisiting the social cost of carbon. Proceedings of the National Academy of Sciences, 114(7), 1518-1523.

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Footnote 75

Yumashev, D., Hope, C., Schaefer, K., Riemann-Campe, K., Iglesias-Suarez, F., Jafarov, E., and Whiteman, G. (2019). Climate policy implications of nonlinear decline of Arctic land permafrost and other cryosphere elements. Nature communications, 10(1), 1900.

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Footnote 76

Additional information regarding results from the updated PAGE model can be found in a recorded event hosted by the United Nations Environment Programme Finance Initiative.

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Footnote 77

A Healthy Environment and a Healthy Economy

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Footnote 78

Bressler, R. D. (2021). The mortality cost of carbon. Nature communications, 12(1), 1-12.

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Footnote 79

Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 (PDF).

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Footnote 80

New York State Department of Environmental Conservation. (2021). Establishing a Value of Carbon Guidelines for Use by State Agencies (PDF).

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Footnote 81

Rennert, K., Prest, B. C., Pizer, W. A., Newell, R. G., Anthoff, D., Kingdon, C., … & Errickson, F. (2021). The Social Cost of Carbon: Advances in Long-Term Probabilistic Projections of Population, GDP, Emissions, and Discount Rates (PDF). Brookings Papers on Economic Activity.

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Footnote 82

Further information on the use of break-even analysis in other jurisdictions can be found in Guidelines for Preparing Economic Analysis (PDF) published by the U.S. Environmental Protection Agency.

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Footnote 83

U.S. Bureau of Labor Statistics: Gasoline price: cyclical trend and market developments.

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Footnote 84

National monthly averages obtained from Kent Group – Monthly average retail prices for regular gasoline.

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Footnote 85

The average number of people per household was obtained from Statistics Canada’s families, households and marital status: Key results from the 2016 Census, and is assumed to remain constant over time.

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Footnote 86

Rezaei, M. (2017). Power to the people: thinking (and rethinking) energy poverty in British Columbia, Canada (Doctoral dissertation, University of British Columbia)

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Footnote 87

Moyser, M., and Fox, D. (2018). Women in Canada: A Gender-based Statistical Report. Statistics Canada.

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Footnote 88

Statistics Canada: Household spending, Canada, regions and provinces

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Footnote 89

Statistics Canada: Population estimates on July 1st, by age and sex

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Footnote 90

The estimated gasoline cost per vehicle is estimated using vehicle counts and fuel demand from the Department’s Motor Vehicle Emission Simulator and fuel prices are from the Departmental Reference Case 2019.

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Footnote 91

Statistics Canada: Distribution of household economic accounts for income, consumption, saving and wealth of Canadian households, 2017

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Footnote 92

Anowar, S., Eluru, N., and Miranda-Moreno, L. F. (2018). How household transportation expenditures have evolved in Canada: a long-term perspective. Transportation, 45(5): 1297-1317.

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Footnote 93

Statistics Canada: The Daily – Survey of Household Spending, 2017

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Footnote 94

Statistics Canada: Distribution of household economic accounts for income, consumption, saving and wealth of Canadian households, 2017.

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Footnote 95

Miller, C., and Savage, I. Does the demand response to transit fare increases vary by income? Transport Policy, 55 (2017) 79-86 (PDF)

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Footnote 96

Statistics Canada: Public Transit in Canada, 2007

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Footnote 97

Iseki, H, and Ali, R. (2014). Net Effects of Gasoline Price Changes on Transit Ridership in U.S. Urban Areas (PDF).

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Footnote 98

Statistics Canada: Labour force characteristics by industry

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Footnote 99

Electricity Human Resources Canada. (2017). Profile of women working in the clean energy sector in Canada (PDF).

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Footnote 100

Conference Board of Canada. (2011). Canada’s Petroleum Refining Sector: An Important Contributor Facing Global Challenges.

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Footnote 101

Statistics Canada (2008), First Results from the Survey of Older Workers, by Pignal, J., Arrowsmith, S., and Ness, A., page 20, Ottawa.

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Footnote 102

Statistics Canada (2018), Labour Force Survey, CANSIM Table 282-0004.

Return to footnote 102 referrer

Footnote 103

Federal/Provincial/Territorial Ministers Responsible for Seniors (2012), Age-Friendly Workplaces: Promoting Older Worker Participation, Human Resources and Skills Development Canada, Gatineau.

Return to footnote 103 referrer

Footnote 104

Government of Canada, “Climate change and health: Populations at risk.”

Return to footnote 104 referrer

Footnote 105

The non-rounded net increase in annualized average administrative costs for primary suppliers is estimated to be $228,197, or $7,606.57 per stakeholder.

Return to footnote 105 referrer

Footnote 106

The non-rounded net decrease in annualized average administrative costs for non-primary supplier RFR regulatees is estimated to be $104,980, or $2,560.49 per stakeholder.

Return to footnote 106 referrer

Footnote 107

The non-rounded net increase in annualized average administrative costs for voluntary credit creators is estimated to be $1,410,463, or $12,706.87 per stakeholder.

Return to footnote 107 referrer

Footnote 108

The non-rounded net increase in annualized average administrative costs for all mandatory and voluntary regulatees is estimated to be $1,533,679, or $10,877.16 per stakeholder.

Return to footnote 108 referrer

Footnote 109

Renewable Fuel Standard, U.S. Department of Energy

Return to footnote 109 referrer

Footnote 110

News release from Environment and Climate Change Canada. “Canada and California team up to tackle vehicle climate pollution.” June 26, 2019.

Return to footnote 110 referrer

Footnote 111

Pan-Canadian Framework on Clean Growth and Climate Change: Strategic Environmental Assessment

Return to footnote 111 referrer

Footnote 112

Achieving a Sustainable Future: A Federal Sustainable Development Strategy for Canada

Return to footnote 112 referrer

Clean Fuel Regulations: SOR/2022-140

TABLE OF PROVISIONS

Clean Fuel Regulations

Interpretation

Application

Requirements for Liquid Fuels

Carbon-Intensity Limits

Reduction Requirement

Registration as Primary Supplier

Compliance Credits

Use

Creation

Reduction of CO2e Emissions

Creation of Provisional Compliance Credits

Registration as Registered Creator

Compliance-Credit Accounts

CO2e-Emission-Reduction Project

Displacement of Fossil Fuel Usage

Land-Use and Biodiversity Criteria for Low-Carbon-Intensity Fuels

Determination of Carbon Intensity

Low-Carbon-Intensity Fuels

Fuel or Other Energy Source for Vehicles

Compliance-Credit Transfer System

General

Transfer of Compliance Credits

Compliance-Credit Clearance Mechanism

Registered Emission-Reduction Funding Program

Reporting

Verification

Obligation to Verify

Requirements Respecting Verification Bodies

Applicable Standards

Excess Compliance Credits

Measurement, Electronic Reporting and Records

Measurement

Electronic Reporting

Recording and Retention of Information

Transitional Provisions

Consequential Amendments

Repeal

Coming into Force

Clean Fuel Regulations

Interpretation

Application

Requirements for Liquid Fuels

Carbon-Intensity Limits

Reduction Requirement

Registration as Primary Supplier

Compliance Credits

Use

Creation

Reduction of CO2e Emissions

Creation of Provisional Compliance Credits

Registration as Registered Creator

Compliance-Credit Accounts

CO2e-Emission-Reduction Project

Displacement of Fossil Fuel Usage

Land-Use and Biodiversity Criteria for Low-Carbon-Intensity Fuels

Determination of Carbon Intensity

Low-Carbon-Intensity Fuels

Fuel or Other Energy Source for Vehicles

Compliance-Credit Transfer System

General

Transfer of Compliance Credits

Compliance-Credit Clearance Mechanism

Registered Emission-Reduction Funding Program

Reporting

Verification

Obligation to Verify

Requirements Respecting Verification Bodies

Applicable Standards

Excess Compliance Credits

Measurement, Electronic Reporting and Records

Measurement

Electronic Reporting

Recording and Retention of Information

Transitional Provisions

Consequential Amendments

Renewable Fuels Regulations

Environmental Violations Administrative Monetary Penalties Regulations

Reduction of CO₂e Emissions

CO₂e-Emission-Reduction Project

Reduction of CO₂e Emissions

CO₂e-Emission-Reduction Project

Contents of Application for Recognition of CO₂e-Emission-Reduction Project