Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations: SOR/2023-240

Canada Gazette, Part II, Volume 157, Number 24

Registration
SOR/2023-240 November 9, 2023

GREENHOUSE GAS POLLUTION PRICING ACT

ENVIRONMENTAL VIOLATIONS ADMINISTRATIVE MONETARY PENALTIES ACT

P.C. 2023-1133 November 9, 2023

Whereas subsection 194(1) of the Greenhouse Gas Pollution Pricing Act ^{footnote a} stipulates that a regulation made under section 192 or 193 of that Act may have effect earlier than the day on which it is made if it so provides and it gives effect to measures referred to in a notice published by the Minister of the Environment;

And whereas the Minister of the Environment published a Notice of intent to amend the Output-Based Pricing System Regulations on October 28, 2022, to announce the intent to make a Regulation under sections 192 and 193 of that Act to ensure continued greenhouse gas emissions reductions, reduce administrative burden and improve implementation;

Therefore, Her Excellency the Governor General in Council, on the recommendation of the Minister of the Environment, makes the annexed Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations under

(a) sections 192, 193 and 198 of the Greenhouse Gas Pollution Pricing Act^{footnote a}; and
(b) section 5^{footnote b} of the Environmental Violations Administrative Monetary Penalties Act ^{footnote c}.

Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations

Output-Based Pricing System Regulations

1 (1) The portion of subsection 1(1) of the Output-Based Pricing System Regulations ^{footnote 1} before paragraph (b) is replaced by the following:

Definition of facility

1 (1) Subject to subsection (6), for the purposes of the Act and these Regulations, facility means

(a) all of the following elements that are operated in an integrated way to carry out a specified industrial activity:
- (i) a site, or multiple sites, at which the specified industrial activity is carried out and the buildings, equipment and other structures and stationary items located on the site or sites, and
- (ii) any other sites used in conjunction with the specified industrial activity, including a quarry, tailings pond, wastewater lagoon or pond and landfill; or

(2) Subsection 1(5) of the Regulations is replaced by the following:

Interpretation

(5) Subject to subsection (6), with respect to a facility

(a) any part of a public road or of a railway track that is bordered on both sides by the facility and used to carry out the facility’s specified industrial activities is deemed to be part of the facility;
(b) for greater certainty, any part of a railway track that is used exclusively to carry out the facility’s specified industrial activities is part of the facility;
(c) for greater certainty, buildings that are used for legal, administrative or management purposes and that are not located where a specified industrial activity is carried out are not included for the purposes of the definition facility in subsection (1); and
(d) if two or more facilities referred to in paragraph (b) of the definition facility in subsection (1), within the same province, have the same person responsible or a person responsible in common and are not operated in an integrated way, they each constitute a separate facility.

Special case

(6) In the case of a facility that is not a covered facility, the specified industrial activities referred to in subsections (1) and (5) are those that would be specified industrial activities if the facility was a covered facility.

2 (1) The definitions Directive 017, Directive PNG017, GHGRP, IPCC Guidelines, 2020 GHGRP and WCI Method in subsection 2(1) of the Regulations are repealed.

(2) The definitions electricity generation facility and specified industrial activity in subsection 2(1) of the Regulations are replaced by the following:

electricity generation facility: means a covered facility, other than one whose primary activity is something other than an industrial activity, that generates electricity as its primary industrial activity, used to generate electricity from fossil fuels and composed of one unit or a group of units. (installation de production d’électricité)
specified industrial activity: means, with respect to a covered facility, an industrial activity referred to in subsection 5(2). (activité industrielle visée)

(3) Subsection 2(1) of the Regulations is amended by adding the following in alphabetical order:

additional industrial activity: means an industrial activity that is not set out in column 1 of Schedule 1, that is recognized by the Minister, including for the purposes of a facility’s designation as a covered facility under subsection 172(1) of the Act, and that is engaged in in a sector that is recognized by the Minister as being at significant risk of competitiveness impacts resulting from carbon pricing and of carbon leakage resulting from carbon pricing. (activité industrielle additionnelle)

(4) Subsection 2(1) of the Regulations is amended by adding the following in alphabetical order:

Quantification Methods: means the document entitled Quantification Methods for the Output-Based Pricing System Regulations, published by the Department of the Environment in 2022. (méthodes de quantification)

(5) Subsection 2(1) of the Regulations is amended by adding the following in alphabetical order:

distribution system: has the same meaning as section 3 of the Act. (réseau de distribution)

(6) Subsection 2(2) of the Regulations is replaced by the following:

Incorporation by reference

(2) Unless otherwise indicated, a reference to any document incorporated by reference into these Regulations, except the GHGRP and the 2020 GHGRP, is incorporated as amended from time to time.

(7) Subsection 2(2) of the Regulations is replaced by the following:

Incorporation by reference

(2) Unless otherwise indicated, a reference to any document incorporated by reference into these Regulations is a reference to the document as amended from time to time.

(8) Section 2 of the Regulations is amended by adding the following after subsection (2):

Accreditation

(3) Despite subsection (2), if ISO Standard 14065 is amended, the previous version of the document may be complied with for a period of four years beginning on the day on which the amended version is published.

(9) Section 2 of the Regulations is amended by adding the following after subsection (3):

Quantification Methods

(4) Despite subsection (2), the version of Quantification Methods to be complied with for a compliance period is the version that was most recently published prior to the day on which that compliance period begins.

3 Subsection 5(2) of the Regulations is replaced by the following:

Specified industrial activities

(2) Output-based standards are established under these Regulations for the industrial activities set out in column 1 of Schedule 1 and for additional industrial activities engaged in at the covered facility.

4 The Regulations are amended by adding the following after section 6:

Cancellation following request

6.1 If the Minister receives a request to cancel a designation of a covered facility during a calendar year and the Minister decides, under subsection 172(3) of the Act, to cancel the designation, that cancellation is effective as of December 31 of the calendar year in which the decision is made.

5 Paragraph 8(b) of the Regulations is replaced by the following:

(b) the primary activity engaged in at the facility is any of the industrial activities set out in column 1 of Schedule 1.

6 The Regulations are amended by adding the following after section 8:

Remote community

8.1 Unless designated by the Minister as a covered facility under subsection 172(1) of the Act, an electricity generation facility is not included in the definition covered facility in section 169 of the Act if the industrial activity set out in paragraph 38(b) or (c), column 1, of Schedule 1 is engaged in at that facility and that facility

(a) generates electricity for general distribution to the public in a geographic area that is neither serviced by an electrical network that distributes electricity and is subject to the standards of the North American Electric Reliability Corporation nor by a distribution system,
(b) is not connected to an electrical network, for the distribution of electricity, that is subject to the standards of the North American Electric Reliability Corporation, and
(c) is not connected to a distribution system.

7 Subsection 9(2) of the Regulations is replaced by the following:

First compliance period

(2) If a facility becomes a covered facility under the Act after January 1 of a given calendar year, its specified period, for the purposes of the definition compliance period in section 169 of the Act, begins on January 1 of the calendar year following

(a) the calendar year during which the facility is registered under subsection 171(2) of the Act, if the facility meets the criteria set out in section 8, or
(b) the calendar year during which the facility was designated as a covered facility under subsection 172(1) of the Act.

8 Paragraph 10.1(1)(i) of the Regulations is replaced by the following:

(i) the requirement to notify the Minister if there is a change in the person responsible, in accordance with section 48.

9 Section 11 of the Regulations is amended by adding the following after subsection (2):

New additional industrial activity

(3) For the purposes of subparagraph (1)(a)(ii), an additional industrial activity that was recognized by the Minister during a calendar year is not taken into account for the annual report for the compliance period that corresponds to that calendar year.

10 Subsection 13(2) of the Regulations is replaced by the following:

Correction of errors or omissions

(2) The person responsible for a covered facility must correct the errors or omissions, identified by a verification body during the verification of the annual report, prior to submitting the annual report to the Minister, if possible.

11 (1) Section 16 of the Regulations is amended by adding the following after subsection (6):

Additional production of evaporated salt

(6.1) If evaporated salt is produced through solution mining at a covered facility where a specified industrial activity set out in item 24, column 1, of Schedule 1 is engaged in, the following rules apply:

(a) for the purposes of section 17, the person responsible for the covered facility must quantify the GHGs from the production of evaporated salt in accordance with the method applicable to the industrial activity set out in item 24, column 1, of Schedule 1; and
(b) for the purposes of sections 31, 36 and 36.2, the industrial activity set out in item 24.1, column 1, of Schedule 1 is deemed not to be engaged in at the covered facility.

(2) The portion of subsection 16(9) of the Regulations before paragraph (a) is replaced by the following:

Additional production of petrochemicals

(9) Subject to subsection (9.1), if a petrochemical product referred to in item 17, column 1, of Schedule 1 is produced at a covered facility where a specified industrial activity set out in item 3 or 4, column 1, of that Schedule is engaged in, the following rules apply:

(3) Section 16 of the Regulations is amended by adding the following after subsection (9):

Parallel production

(9.1) If a covered facility has at least one refinery that is engaged in a specified industrial activity set out in item 3, column 1, of Schedule 1, and one petrochemical plant, that is engaged in a specified industrial activity referred to in item 17, column 1, of Schedule 1, subsection (9) only applies to the refinery.

(4) Paragraph 16(10)(b) of the French version of the Regulations is replaced by the following:

b) pour l’application des articles 31, 36 et 36.2, l’activité industrielle prévue à l’alinéa 26c) de l’annexe 1 est réputée ne pas être exercée à l’installation assujettie.

12 (1) The descriptions of E_j and GWP_j in subsection 17(1) of the Regulations are replaced by the following:

E_j: is the quantity of each GHG type “j” from the covered facility during a compliance period, for each specified emission type, determined in accordance with subsections (2) to (4);
GWP_j: is the global warming potential of the GHG type “j” applicable to the compliance period and, if it is used to determine the quantities referred to in the descriptions of A, C and F in subsection 37(1), for the reference year “i”, the global warming potential applicable to the compliance period in respect of which the output-based standard is being calculated;

(2) Subsections 17(2) to (4.1) of the Regulations are replaced by the following:

Quantity of each GHG

(2) The quantity of a GHG type “j” from a covered facility during a compliance period for a specified emission type “i” is the sum of the following quantities, determined in accordance with the applicable requirements set out in Quantification Methods:

(a) the quantities of that GHG from industrial activities set out in column 1 of Schedule 1 and set out in column 2 of the table to the Part of Schedule 3 that is applicable to those industrial activities, for a specified emission type set out in column 1 of that table;
(b) the quantities of that GHG from those industrial activities, but not set out in column 2 of the table to the Part of Schedule 3 that applies to those activities or for a specified emission type not set out in column 1 of that table; and
(c) any quantity of that GHG that is not referred to in paragraph (a) or (b).

Sampling, analysis and measurement requirements

(3) If the quantity of a GHG is determined in accordance with subsection (2), the sampling, analysis and measurement requirements that apply are those set out in Quantification Methods.

Missing data

(4) For the purposes of subsection (2), if, for any reason beyond the control of the person responsible for a covered facility, the data required to quantify the GHGs from a covered facility are missing for a given period of a compliance period, replacement data for the given period must be calculated in accordance with Quantification Methods.

13 Sections 18 and 19 of the Regulations are replaced by the following:

Additional generation of electricity

18 For the purposes of section 17, the quantities of the GHGs for specified emission types from the generation of electricity using fossil fuels by a covered facility — other than a covered facility referred to in paragraph 11(1)(c) — are determined in accordance with the methods that are applicable to any of the industrial activities engaged in at the covered facility.

14 (1) The description of GWP_j in subsection 20(1) of the Regulations is replaced by the following:

GWP_j: is the global warming potential of the GHG type “j” applicable to the compliance period;

(2) Subsection 20(2) of the Regulations is replaced by the following:

Quantity of each GHG

(2) The quantity of a GHG type “j” generated by a unit during a compliance period for a specified emission type “i” is the sum of the following quantities, determined in accordance with the applicable requirements set out in Quantification Methods:

(a) the quantities of the GHG that is set out in column 2 of the table to Part 38 of Schedule 3 for a specified emission type set out in column 1; and
(b) any quantity of the GHG that is not referred to in paragraph (a).

(3) Subsections 20(4) and (5) of the Regulations are replaced by the following:

Sampling, analysis and measurement requirements

(4) If the quantity of a GHG is determined in accordance with subsection (2), the sampling, analysis and measurement requirements that apply are those set out in Quantification Methods.

Missing data

(5) For the purposes of subsection (2), if, for any reason beyond the control of the person responsible for a covered facility, the data required to quantify GHGs generated by a unit are missing for a given period of a compliance period, replacement data for the given period must be calculated in accordance with Quantification Methods.

15 The Regulations are amended by adding the following after section 22:

Measuring device

22.1 Unless otherwise provided for in a method set out in Quantification Methods, any measuring device that is used to determine a quantity for the purposes of these Regulations must

(a) be installed, operated, maintained and calibrated in accordance with the manufacturer’s specifications, or, if those specifications are not available, with any applicable generally recognized national or international industry standard; and
(b) maintain accuracy within plus or minus 5%.

16 Section 25 of the Regulations is replaced by the following:

Continuous Emissions Monitoring System

25 If a continuous emissions monitoring system is used to quantify GHGs under these Regulations, the person responsible for the covered facility must ensure that the system complies with the requirements set out in Quantification Methods.

17 Section 26 of the Regulations is replaced by the following:

Alternative method

26 Despite sections 17 and 20, the person responsible for a covered facility may use a method other than a method set out in Quantification Methods if they have a permit issued in accordance with section 28.

18 The portion of subsection 28(1) of the Regulations before paragraph (d) is replaced by the following:

Conditions of issuance

28 (1) The Minister must issue the permit to use a method of quantification other than the method set out in Quantification Methods if

(a) the person responsible for the covered facility establishes that, at the time of the application, it is not technically or economically feasible to use the method set out in Quantification Methods;
(b) the person responsible for the covered facility demonstrates that the method being proposed is at least as rigorous as the requirements set out in Quantification Methods and provides equivalent results to those that would have been obtained from those requirements;
(c) the person responsible for the covered facility provides a plan describing measures that will be taken to enable the use of the method set out in Quantification Methods and the implementation period for that plan, up to a maximum of two years; and

19 (1) Paragraph 31(1)(a) of the Regulations is replaced by the following:

(a) in the case of production from a specified industrial activity set out in items 1 to 37 and 39 to 44, column 1, of Schedule 1, in the units of measurement set out in column 2 of Schedule 1 for that industrial activity, and in accordance with any requirements set out in the applicable part of Schedule 3;

(2) Subparagraph 31(1)(b)(i) of the Regulations is replaced by the following:

(i) quantified in whole for the compliance period in accordance with the requirements set out in sections 3 and 4 of Part 38 of Schedule 3, or

(3) Paragraph 31(1)(c) of the Regulations is replaced by the following:

(c) in the case of production from an additional industrial activity, in the units of measurement specified by the Minister for that activity.

(4) The portion of subsection 31(2) of the English version of the Regulations before paragraph (a) is replaced by the following:

Measuring device

(2) Any measuring device that is used to determine a quantity for the purposes of these Regulations must

(5) Paragraphs 31(2)(a) and (b) of the Regulations are replaced by the following:

(a) be installed, operated, maintained and calibrated in accordance with the manufacturer’s specifications or, if those specifications are not available, any applicable generally recognized national or international industry standard; and
(b) maintain accuracy within plus or minus 5%.

20 Paragraphs 32(1)(a) and (b) of the Regulations are replaced by the following:

(a) if a unit uses only one fossil fuel to generate electricity, in accordance with subsection 1(1) and section 2 of Part 38 of Schedule 3; and
(b) if a unit uses a mixture of fossil fuels or a mixture of biomass and fossil fuels to generate electricity, in accordance with subsections 1(2) and (3) and section 2 of Part 38 of Schedule 3.

21 Paragraphs 34(1)(b) and (c) of the Regulations are replaced by the following:

(b) for a covered facility not referred to in paragraph (c), determined by the following formula if the thermal energy is produced from the combustion of both fossil fuels and biomass:

HF ÷ (HF + B)

where

HF

is determined by the formula

where

QF_i

is the quantity of fossil fuel of type “i” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with subsection 4(2) of Part 38 of Schedule 3,

HHV_i

is the higher heating value of the fossil fuel of type “i” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with Quantification Methods, and

i

is the i^th fossil fuel type combusted in the facility during the compliance period, where “i” goes from 1 to n and where n is the number of types of fossil fuels combusted, and

B

is determined by the formula

where

QBB_k

is the quantity of biomass fuel type “k” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with subsection 4(2) of Part 38 of Schedule 3 and Quantification Methods,

HHV_k

is the higher heating value for biomass fuel type “k” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with Quantification Methods, and

k

is the k^th biomass fuel type combusted in the facility during the compliance period, where “k” goes from 1 to m and where m is the number of types of biomass fuels combusted; and
(c) for an electricity generation facility, determined by the following formula when the thermal energy is produced from the combustion of both fossil fuels and biomass:

HF ÷ (HF + B)

where

HF

is determined by the formula

where

QFi

is the quantity of fossil fuel of type “i” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with subsection 1(3) of Part 38 of Schedule 3,

HHVi

is the higher heating value of the fossil fuel of type “i” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with Quantification Methods, and

i

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

B

is determined by the formula

where

QBB_k

is the quantity of biomass fuel type “k” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with subsection 1(3) of Part 38 of Schedule 3,

HHV_k

is the higher heating value for biomass fuel type “k” combusted in the facility for the generation of thermal energy, during the compliance period determined in accordance with Quantification Methods, and

k

is the k^th biomass fuel type combusted in the facility during the compliance period, where “k” goes from 1 to m and where m is the number of types of biomass fuels combusted.

22 The description of B in subsection 35(1) of the Regulations is replaced by the following:

B is the quantity of CO₂ captured at the covered facility that is stored during the compliance period in a storage project, determined using Quantification Methods, expressed in CO₂e tonnes.

23 (1) Subsection 36(1) of the Regulations is replaced by the following:

General rule

36 (1) Subject to subsection (2) and sections 16, 36.1, 36.2 and 42, the person responsible for a covered facility, other than an electricity generation facility, must determine the GHG emissions limit that applies to that covered facility for each compliance period, expressed in CO₂e tonnes, in accordance with the formula

where

A_i

is the covered facility’s production from each specified industrial activity “i” during the compliance period, quantified in accordance with section 31;

B_i

is the following output-based standard applicable to the specified industrial activity “i”, as the case may be:

(a) for a specified industrial activity set out in column 1 of Schedule 1 and for which an output-based standard is set out in column 3 of that Schedule, that standard,
(b) for a specified industrial activity set out in column 1 of Schedule 1 and for which column 3 of that Schedule sets out that an output-based standard must be calculated in accordance with section 37, the output-based standard calculated in accordance with that section, and
(c) for an additional industrial activity, the output-based standard calculated in accordance with section 37;

C

is the following tightening rate applicable to the specified industrial activity “i”, as the case may be:

(a) 0% for the specified industrial activity set out in item 38, column 1, of Schedule 1,
(b) 1% for the specified industrial activities set out in paragraph 3(c) and items 7, 8, 13, 17, 19, 20, and 34, column 1, of Schedule 1, and
(c) 2% for all other specified industrial activities;

D

is the calendar year that corresponds to the compliance period; and

i

is the i^th specified industrial activity where “i” goes from 1 to n and where n is the total number of specified industrial activities engaged in at the covered facility.

(2) Subsection 36(1) of the Regulations is replaced by the following:

General rule

where

A_i

is the covered facility’s production from each specified industrial activity “i” during the compliance period, quantified in accordance with section 31;

B_i

is the following output-based standard applicable to the specified industrial activity “i”, as the case may be:

(a) for a specified industrial activity set out in column 1 of Schedule 1 and for which an output-based standard is set out in column 3 of that Schedule, that standard,
(b) for a specified industrial activity set out in column 1 of Schedule 1 and for which column 3 of that Schedule sets out that an output-based standard must be calculated in accordance with section 37, the output-based standard calculated in accordance with that section, and
(c) for an additional industrial activity, the output-based standard calculated in accordance with section 37;

C

is the following tightening rate applicable to the specified industrial activity “i”, as the case may be:

(a) 0% for the specified industrial activity set out in item 38, column 1, of Schedule 1,
(b) 1% for the specified industrial activities set out in paragraph 3(c) and items 7, 8, 13, 17, 19, 20, 34, 40, 41 and 43, column 1, of Schedule 1, and
(c) 2% for all other specified industrial activities;

D

is the calendar year that corresponds to the compliance period; and

i

is the i^th specified industrial activity where “i” goes from 1 to n and where n is the total number of specified industrial activities engaged in at the covered facility.

(3) Subsection 36(4) of the Regulations is replaced by the following:

Clarification — fertilizer

(4) For greater certainty, if the industrial activity set out in paragraph 29(b), column 1, of Schedule 1 and also any of the industrial activities set out in paragraph 29(c), (d) or (e), column 1, of Schedule 1 are engaged in at the covered facility, the output-based standard applicable to the industrial activity set out in that paragraph 29(b) applies and the output-based standard applicable to the industrial activity set out in that paragraph 29(c), (d) or (e) applies, as the case may be.

(4) Section 36 of the Regulations is amended by adding the following after subsection (4):

New additional industrial activity

(4.1) For the purposes of subsection (1), an additional industrial activity that was recognized by the Minister during a calendar year is not included in the determination of the GHG emissions limit for the compliance period that corresponds to that calendar year.

24 (1) Subsections 36.2(2) and (3) of the Regulations are replaced by the following:

Different output-based standard

(2) The GHG emissions limit that applies to the covered facility for a compliance period, expressed in CO₂e tonnes, is determined in accordance with the formula

where

A_i

is the covered facility’s production during the compliance period, quantified in accordance with section 31,

(a) from each specified industrial activity “i”, except the industrial activity set out in paragraph 38(c), column 1, of Schedule 1, and
(b) from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, other than from equipment referred to in the descriptions of E, G and H;

B_i

is the following output-based standard applicable to the specified industrial activity “i”, as the case may be:

(a) for a specified industrial activity set out in column 1 of Schedule 1 and for which an output-based standard is set out in column 3 of that Schedule, that standard,
(b) for a specified industrial activity set out in column 1 of Schedule 1 and for which column 3 of that Schedule sets out that an output-based standard must be calculated in accordance with section 37, the output-based standard calculated in accordance with that section, and
(c) for an additional industrial activity, the output based standard calculated in accordance with section 37;

C

is the following tightening rate applicable to the specified industrial activity “i”, as the case may be:

(a) 0% for the specified industrial activity set out in item 38, column 1, of Schedule 1,
(b) 1% for the specified industrial activities set out in paragraph 3(c) and items 7, 8, 13, 17, 19, 20 and 34, column 1, of Schedule 1, and
(c) 2% for all other specified industrial activities;

D

is the calendar year that corresponds to the compliance period;

E

is the gross amount of electricity generated during the compliance period by the equipment that started generating electricity from gaseous fuels on or after January 1, 2021, and is designed to operate at a thermal energy to electricity ratio of less than 0.9, from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, quantified in accordance with section 31;

F

is the output-based standard set out in subsection 36.1(2) that is applicable for the compliance period;

G

is, for equipment with increased electricity generation capacity and a thermal energy to electricity ratio of less than 0.9, other than equipment referred to in the description of E, the gross amount of electricity generated during the compliance period attributed to the capacity added to the equipment, from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, quantified in accordance with section 31 and subsection (3);

H

is, for equipment with increased electricity generation capacity and a thermal energy to electricity ratio of less than 0.9, other than equipment referred to in the description of E, the gross amount of electricity generated during the compliance period attributed to the capacity of the equipment before the additional capacity was added, from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, quantified in accordance with section 31 and subsection (3);

I

is the output-based standard set out in item 38, column 3, of Schedule 1 that is applicable to the specified industrial activity set out in paragraph 38(c), column 1 of that Schedule; and

i

is the i^th specified industrial activity where “i” goes from 1 to n and where n is the total number of specified industrial activities engaged in at the covered facility.

Apportionment of electricity generation

(3) For the purposes of the descriptions of G and H in subsection (2), the gross amount of electricity generated by the equipment referred to in those descriptions is apportioned, using engineering estimates, to the equipment’s capacity added to the equipment and to the capacity of the equipment before the additional capacity was added, based on the ratio of the amount of its increased capacity to its total capacity, taking into account the increased capacity.

(2) Subsection 36.2(2) of the Regulations is replaced by the following:

Different output-based standard

(2) The GHG emissions limit that applies to the covered facility for a compliance period, expressed in CO₂e tonnes, is determined in accordance with the formula

where

A_i

is the covered facility’s production during the compliance period, quantified in accordance with section 31,

(a) from each specified industrial activity “i”, except the industrial activity set out in paragraph 38(c), column 1, of Schedule 1, and
(b) from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, other than from equipment referred to in the descriptions of E, G and H;

B_i

is the following output-based standard applicable to the specified industrial activity “i”, as the case may be:

(a) for a specified industrial activity set out in column 1 of Schedule 1 and for which an output-based standard is set out in column 3 of that Schedule, that standard,
(b) for a specified industrial activity set out in column 1 of Schedule 1 and for which column 3 of that Schedule sets out that an output-based standard must be calculated in accordance with section 37, the output-based standard calculated in accordance with that section, and
(c) for an additional industrial activity, the output based standard calculated in accordance with section 37;

C

is the following tightening rate applicable to the specified industrial activity “i”, as the case may be:

(a) 0% for the specified industrial activity set out in item 38, column 1, of Schedule 1,
(b) 1% for the specified industrial activities set out in paragraph 3(c) and items 7, 8, 13, 17, 19, 20, 34, 40, 41 and 43, column 1, of Schedule 1, and
(c) 2% for all other specified industrial activities;

D

is the calendar year that corresponds to the compliance period;

E

F

is the output-based standard set out in subsection 36.1(2) that is applicable for the compliance period;

G

H

is, for equipment with increased electricity generation capacity and a thermal energy to electricity ratio of less than 0.9, other than equipment referred to in the description of E, the gross amount of electricity generated during the compliance period attributed to the capacity of the equipment before the additional capacity was added, from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, quantified in accordance with section 31 and subsection (3);

I

is the output-based standard set out in item 38, column 3, of Schedule 1 that is applicable to the specified industrial activity set out in paragraph 38(c), column 1 of that Schedule; and

i

is the i^th specified industrial activity where “i” goes from 1 to n and where n is the total number specified industrial activities engaged in at the covered facility.

25 (1) Subsection 37(1) of the Regulations is replaced by the following:

Calculated output-based standard

37 (1) Subject to subsection (3) and sections 38 and 39, the output-based standard that is applicable to a specified industrial activity of a covered facility, for which an output-based standard must be calculated in accordance with this section, is calculated in accordance with the formula

where

A

is the quantity of GHGs that are emitted from the covered facility for reference year “i”, determined in accordance with section 35, expressed in CO₂e tonnes;

B

is the allocation for net thermal energy for reference year “i” and is

(a) determined by the formula
0.062 CO₂e tonnes/gigajoules × (M − N) × O

where

M

is the quantity of thermal energy produced by the covered facility that was sold to another covered facility in reference year “i”, as indicated by the quantity of thermal energy on sales receipts or determined by another objective method, expressed in gigajoules,

N

is the quantity of thermal energy that was bought from other covered facilities and not subsequently sold in reference year “i”, as indicated by the quantity of thermal energy on sales receipts or by another objective method, expressed in gigajoules, and

O
is the ratio of heat from the combustion of fossil fuels to produce thermal energy and is,
- (i) if M is greater than N, the ratio of heat determined under section 34 for reference year “i” for the covered facility, or
- (ii) if M is less than N, the ratio of heat determined under section 34 for reference year “i” for the covered facility from which the thermal energy was purchased, and
(b) 0 for all reference years if the absolute value of the quotient obtained by dividing the sum of the results determined under paragraph (a) for each reference year “i” by the number of reference years is less than the quotient determined by the formula

Detailed information can be found in the surrounding text.

C

is the total quantity of GHGs from all specified industrial activities engaged in at the facility for reference year “i” other than the industrial activity for which the output-based standard is being calculated, determined in accordance with sections 17 and 18;

D

is the production from a covered facility from the specified industrial activity for which the output-based standard is being calculated for reference year “i” quantified in accordance with section 31;

E

is the GHG emissions reduction factor applicable to the specified industrial activity for which the output-based standard is being calculated and is

(a) 95% for a specified industrial activity set out in paragraph 7(c), 8(b) or (c) or 20(d), column 1, of Schedule 1,
(b) 90% for a specified industrial activity set out in item 22 or paragraph 23(a) or 29(d), column 1, of Schedule 1, and
(c) 80% for all other specified industrial activities;

F

is the total quantity of GHGs from an activity engaged in at the facility, for reference year “i”, that is not a specified industrial activity, determined in accordance with sections 17 and 18, if

(a) with respect to a covered facility whose primary activity is an industrial activity,
- (i) that quantity accounts for 20% or more of the total quantity of GHGs from a covered facility for that reference year, determined in accordance with sections 17 and 18, or
- (ii) the revenue, in dollars, attributable to the sale of the product produced by the facility from that industrial activity accounts for 20% or more of the revenue, in dollars, attributable to the sale of all products produced by the facility from all of the facility’s industrial activities for that reference year, or
(b) with respect to a covered facility whose primary activity is not an industrial activity,
- (i) the activity is not an industrial activity, or
- (ii) the quantity of GHGs from an industrial activity accounts for 20% or more of the total quantity of GHGs from a covered facility, for that reference year, determined in accordance with sections 17 and 18; and

G

is the quantity of CO₂ determined for the purposes of the description B in section 35, from all activities engaged in at the facility for reference year “i” other than the industrial activity for which the output-based standard is being calculated; and

i

is the i^th reference year, where “i” goes from 1 to n and where n is the number of reference years, determined in accordance with subsection (2).

(2) The portion of subsection 37(2) of the Regulations before paragraph (b) is replaced by the following:

Reference years

(2) Subject to paragraph (2.1)(a), the reference years applicable to the specified industrial activities that are engaged in at a covered facility for which an emissions limit is calculated for a compliance period are

(a) except for a covered facility referred to in paragraph (b),
- (i) the 2017, 2018 and 2019 calendar years, if the data are available for those years,
- (ii) the three calendar years preceding the compliance period, if the data are not available for the 2017, 2018, and 2019 calendar years, or
- (iii) the compliance period, if the data are not available for the years specified in subparagraphs (i) and (ii); and

(3) Section 37 of the Regulations is amended by adding the following after subsection (2):

New activity

(2.1) For the purposes of subsection (1), if the calculation of the emissions limit for a compliance period takes into account a specified industrial activity that began to be engaged in at the covered facility during that compliance period and for which an output-based standard has not previously been calculated under this section

(a) the applicable reference years with respect to that specified industrial activity are that compliance period and the two calendar years following it; and
(b) the determination of the output-based standard for that specified industrial activity is to be made based on projections, made using engineering estimates, for the applicable reference years.

Attributing of emissions

(2.2) For the purposes of the descriptions of C, F and G in subsection (1), the method used to attribute the quantity of GHGs to an activity must be rigourous, objective and based on sound engineering principles. The same method must be used for each reference year and no quantity of GHGs may be attributed to more than one activity.

26 Section 39 of the Regulations are replaced by the following:

Recalculation of output-based standard

39 If an output-based standard applicable to a specified industrial activity was calculated in accordance with subsection 37(2.1) for a compliance period, it must be recalculated in accordance with subsection 37(1) for the third compliance period following the compliance period for which the original calculation was done. The reference years that must be used for the recalculation are the three calendar years that precede that third compliance period.

27 Section 40 of the Regulations is repealed.

28 (1) Subsection 45(2) of the Regulations is replaced by the following:

Continuous Emissions Monitoring System

(2) For each compliance period during which a person responsible for the covered facility uses a continuous emissions monitoring system, they must comply with the record keeping requirements set out in Quantification Methods.

(2) Section 45 of the Regulations is amended by adding the following after subsection (3):

Provision of records

(4) A person who is required to keep a record of information under subsection (1), must, on the Minister’s request, provide a copy of that record to the Minister without delay.

29 (1) The portion of paragraph 49(1)(b) of the Regulations before subparagraph (i) is replaced by the following:

(b) conduct the verification in accordance with the version of ISO Standard 14064-3 published by the International Organization for Standardization in 2006 and entitled Greenhouse gases — Part 3: Specification with guidance for the validation and verification of greenhouse gas assertions, the version of that Standard, published in 2019 and entitled Greenhouse gases — Part 3: Specification with guidance for the verification and validation of greenhouse gas statements, or the subsequent published version, set out in their accreditation, by applying methods that allow it to make a determination to a reasonable level of assurance, as defined in that standard, on whether

(2) Subsection 49(2) of the Regulations is replaced by the following:

Material discrepancy

(2) For the purpose of the verification of a covered facility’s annual report or corrected report, a material discrepancy exists when

(a) with respect to GHGs from covered facilities that have emitted a quantity of GHGs of less than 500 kt of CO₂e during the compliance period,
- (i) in the case of an error or omission respecting GHGs that is identified during the verification and that may be quantified, the result, expressed as a percent, determined by the formula, is equal to or greater than 5%:
  
  A ÷ B × 100
  
  where
  
  A
  
  is the absolute value of the overstatement or understatement resulting from the error or omission, expressed in CO₂e tonnes, and
  
  B
  
  is the total quantity of GHGs reported in the annual report or corrected report, expressed in CO₂e tonnes, and
- (ii) in the case of the aggregate of all errors and omissions respecting GHGs that are identified during the verification and that may be quantified, the result, expressed as a percent, determined by the formula, is equal to or greater than 5%:
  
  A ÷ B × 100
  
  where
  
  A
  
  is the absolute value of the net result of all overstatements and understatements resulting from all errors and omissions, expressed in CO₂e tonnes, and
  
  B
  
  is the total quantity of GHGs reported in the annual report or corrected report, expressed in CO₂e tonnes;
(b) with respect to GHGs from covered facilities that emitted a quantity of GHGs that is equal to or greater than 500 kt of CO₂e during the compliance period,
- (i) in the case of an error or omission respecting GHGs that is identified during the verification and that may be quantified, the result, expressed as a percent, determined by the formula, is equal to or greater than 2%:
  
  A ÷ B × 100
  
  where
  
  A
  
  is the absolute value of the overstatement or understatement resulting from an error or omission, expressed in CO₂e tonnes, and
  
  B
  
  is the total quantity of GHGs reported in the annual report or corrected report, expressed in CO₂e tonnes, and
- (ii) in the case of the aggregate of all errors and omissions respecting GHGs that are identified during the verification and that may be quantified, the result, expressed as a percent, determined by the formula, is equal to or greater than 2%:
  
  A ÷ B × 100
  
  where
  
  A
  
  is the absolute value of the net result of all overstatements and understatements resulting from all errors and omissions, expressed in CO₂e tonnes, and
  
  B
  
  is the total quantity of GHGs reported in the annual report or corrected report, expressed in CO₂e tonnes; and
- (c) with respect to the production from a specified industrial activity that is used in the calculation of the emissions limit, in the case of an error or omission respecting the quantification of the production that is identified during the verification and may be quantified, the result, expressed as a percent, determined by the formula, is equal to or greater than 5%:
  
  A ÷ B × 100
  
  where
  
  A
  
  is the absolute value of the overstatement or understatement resulting from an error or omission expressed in the applicable unit of measure, and
  
  B
  
  is the production from the specified industrial activity in question that is reported in the annual report or corrected report, expressed in the applicable unit of measure.

30 Paragraph 51(1)(b) of the Regulations is replaced by the following:

(b) two calendar years have passed since a verification body has visited the covered facility for the purposes of verifying an annual report or corrected report;

31 Subsection 53(1) of the Regulations is replaced by the following:

Determination

53 (1) The Minister may establish the emissions limit or determine the quantity of GHGs emitted from the covered facility for the compliance period if

(a) there is a material discrepancy with respect to the total quantity of GHGs from the covered facility or the production from one or more specified industrial activities used in the calculation of the emissions limit reported in the annual report or the corrected report for the compliance period;
(b) the verification opinion referred to in paragraph 3(n) of Schedule 5 that is included in the verification report that accompanies an annual report or corrected report for the compliance period indicates that it is impossible to determine that a material discrepancy does not exist or that the annual report or corrected report was prepared in accordance with these Regulations;
(c) the emissions limit for the covered facility that is indicated in the annual report or corrected report for the compliance period was not calculated in accordance with these Regulations and any resulting error was equal to or greater than 2%; or
(d) the annual report for the compliance period was not submitted to the Minister.

32 Subparagraphs 58(g)(ii) to (iv) of the Regulations are replaced by the following:

(ii) the province or program authority referred to in subsection 78(1) that issued the units or credits,
(iii) the date of their retirement or the date they are designated for use exclusively as a compliance unit for the purposes of remittance to the Minister under section 174, paragraph 178(1)(a) or subsection 181(2) of the Act, as the case may be,
(iv) the serial numbers assigned to them by the province or program authority referred to in subsection 78(1),

33 Section 59 of the Regulations is replaced by the following:

Surplus credits

59 (1) For the purposes of section 175 of the Act and subject to subsection (2), the number of surplus credits, equivalent to the difference between the emissions limit and the quantity of GHGs emitted from the covered facility, that the Minister issues is based on what is reported in the annual report submitted for the compliance period if the emissions limit that was set out in the report was calculated in accordance with these Regulations, unless a material discrepancy within the meaning of subsection 49(2) exists with respect to the total quantity of GHGs or the production from one of the specified industrial activities that is used in the calculation of the emissions limit for the compliance period.

Exception

(2) The Minister will not issue surplus credits if the Minister has established the emissions limit or determined the quantity of GHGs emitted from the covered facility for the compliance period under section 53.

34 Section 62 of the Regulations is replaced by the following:

Corrected report

62 (1) If the notice indicated that the error or omission, or the aggregate of all errors and omissions, would have constituted a material discrepancy under subsection 49(2), a corrected report, along with a verification report prepared in accordance with section 52, must be submitted to the Minister by the person responsible within 120 days after the day on which the notice is submitted.

Content

(2) The corrected report must include the information referred to in sections 11 and 12 and, under a heading, the following information:

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

35 Paragraph 63(1)(b) of the Regulations is replaced by the following:

(b) in the case of a verified corrected report, 120 days after the day on which the Minister required it.

36 Sections 64 and 65 of the Regulations are replaced by the following:

Change in obligations

64 (1) For the purposes of section 178 of the Act, the revised compensation to be paid or remitted or the number of surplus credits to be issued, as the case may be, is equal to the difference between the result of the assessment made in accordance with section 44, and reported in the annual report, and the result that is reported in the corrected report.

Revised compensation

(2) For the purposes of paragraph 178(1)(a) of the Act, any revised compensation is to be provided by means of an excess emissions charge payment or a remittance of compliance units. Revised compensation is to be provided if the difference referred to in subsection (1) is greater than or equal to 500 CO₂e tonnes.

Issuance of surplus credits

(3) For the purposes of paragraph 178(1)(b) of the Act and subject to subsection (4), the Minister may issue a number of surplus credits that is equivalent to the difference between, as the case may be,

(a) the number of surplus credits that corresponds to the result obtained under section 44 based on the corrected report and the number of surplus credits issued under section 175 of the Act based on the annual report; or
(b) the applicable emissions limit and the quantity of GHGs emitted from the covered facility that are reported in the corrected report, if the emissions limit that was set out in the corrected report was calculated in accordance with these Regulations.

Exception

(4) The Minister will not issue surplus credits if

(a) a material discrepancy within the meaning of subsection 49(2) exists with respect to the total quantity of GHGs reported in the corrected report or the production from one of the specified industrial activities that is used in the calculation of the emissions limit reported in the corrected report for the compliance period; or
(b) the emissions limit or quantity of GHGs emitted from the covered facility is determined by the Minister for the compliance period under section 53.

37 Section 67 of the Regulations is replaced by the following:

Charge

67 An excess emissions charge payment made for the purposes of subsection 64(2) must be made in the manner set out in section 55.

38 (1) Subsection 69(1) of the Regulations is replaced by the following:

Regular-rate compensation deadline

69 (1) With respect to revised compensation, the regular rate referred to in subsection 174(3) of the Act applies for a period of 45 days after the day on which the corrected report must be submitted.

(2) Subsection 69(2) of the French version of the Regulations is replaced by the following:

Délai de compensation — taux élevé

(2) Si la compensation n’est pas versée en entier dans le délai fixé au paragraphe (1), le délai de compensation à taux élevé visé au paragraphe 174(4) de la Loi court pendant soixante jours à compter de la fin du délai prévu au paragraphe (1).

39 (1) Subsection 78(1) of the Regulations is replaced by the following:

Compliance unit

78 (1) A unit or credit is to be recognized as a compliance unit if

(a) it is issued by a province or by a program authority on behalf of a province;
(b) it is issued under an offset protocol and offset program that is set out on the list published on the Department of the Environment’s website;
(c) it is eligible for use as a method of compensation or compliance with respect to a pricing mechanism for GHG emissions in the province in which it was issued; and
(d) it corresponds to a GHG reduction or removal of one CO₂e tonne.

(2) Paragraph 78(2)(f) of the English version of the Regulations is replaced by the following:

(f) measures to ensure that, for a GHG reduction or removal of one CO₂e tonne, one credit or unit is issued and the unit or credit is not used more than once;

(3) Subparagraph 78(4)(d)(ii) of the Regulations is replaced by the following:

(ii) is not suspended by the accreditation organization that issued its accreditation nor suspended at the time the verification relative to the issuance of the unit or credit occurred or at the time the verification report related to the issuance of the unit or credit was signed; and

(4) Subsection 78(4) of the Regulations are amended by striking out “and” at the end of paragraph (c) and by adding the following after paragraph (d):

(e) be designated for use exclusively as a compliance unit for the purposes of remittance to the Minister under section 174, paragraph 178(1)(a) or subsection 181(2) of the Act.

40 Schedule 1 to the Regulations is amended by replacing the references after the heading “SCHEDULE 1” with the following:

(Subsections 2(1) and 5(2), paragraph 8(b), section 8.1, subparagraphs 11(1)(b)(iii) and (iv), clauses 11(1)(c)(iii)(A) and (B), subsections 12(2) and (3), section 16, paragraph 17(2)(a), subsections 22(2), 31(1), 32(1) and 36(1) to (4), section 36.1, subsections 36.2(2) and 37(1), sections 38 and 41, subsections 41.1(2) and 41.2(2), sections 41.3 and 42, subsection 1(1.1) of Part 3 of Schedule 3, subparagraphs 1(2)(b)(i) and (ii) and (c)(i) of Part 3 of Schedule 3, section 1 of Part 4 of Schedule 3, sections 1 and 2 of Part 7 of Schedule 3, section 1 of Part 37 of Schedule 3 and subparagraphs 3(g)(ii) and 3(h)(iii) of Schedule 5)

41 Schedule 1 to the Regulations is amended by adding the following in numerical order:
Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO₂e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
3.1	Surface mining of oil sands and extraction of bitumen	barrels of bitumen	0.0266	Part 3.1

42 (1) The portion of item 17 of Schedule 1 of the English version of to the Regulations before paragraph (a) in column 1 is replaced by the following:
Item	Column 1 Industrial Activity
17	Production of the following petrochemical products from petroleum and liquefied natural gas or from feedstocks derived from petroleum:

(2) Item 17 of Schedule 1 to the Regulations is amended by adding the following after paragraph (f):
Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO₂e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
17	(g) ethylene glycol with six or fewer monomer units	tonnes of ethylene glycol with six or fewer monomer units	0.326	Part 17

43 Schedule 1 to the Regulations is amended by adding the following in numerical order:
Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO₂e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
24.1	Production of evaporated salt through solution mining	tonnes of evaporated salt at a concentration of at least 99% of NaCl	0.153	Part 24.1

44 The portion of item 26 of Schedule 1 to the Regulations before paragraph (a) in column 1 is replaced by the following:
Item	Column 1 Industrial Activity
26	Production of metal or diamonds from the mining and milling of ore or kimberlite

45 (1) The portion of paragraph 29(a) of Schedule 1 to the Regulations in column 3 is replaced by the following:
Item	Column 3 Output-based standard (CO₂e tonnes/unit of measurement)
29(a)	0.310

(2) The portion of paragraph 29(c) of Schedule 1 to the Regulations in column 3 is replaced by the following:
Item	Column 3 Output-based standard (CO₂e tonnes/unit of measurement)
29(c)	0.132

(3) Item 29 of Schedule 1 to the Regulations is amended by adding the following after paragraph (d):
Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO₂e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
29	(e) granular urea in addition to producing anhydrous ammonia or aqueous ammonia by the steam reforming of hydrocarbons	Tonnes of granular urea	0.159	Part 29

46 The portion of item 30 of Schedule 1 to the Regulations in column 3 is replaced by the following:
Item	Column 3 Output-based standard (CO₂e tonnes/unit of measurement)
30	0.102

47 Schedule 1 to the Regulations is amended by adding the following in numerical order:
Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO₂e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
35.1	Production of malt	Tonnes of malt	0.117	Part 35.1

48 The portion of paragraph 36(b) of Schedule 1 to the Regulations in column 1 is replaced by the following:
Item	Column 1 Industrial Activity
36	(b) pulp from wood, other plant material or paper or any product derived directly from pulp or a pulping process — excluding specialty products and products referred to in subitem 39(3) — at a facility not equipped with a recovery boiler, lime kiln or pulping digester

49 The portion of item 37 of Schedule 1 to the Regulations in column 1 is replaced by the following:
Item	Column 1 Industrial Activity
37	Main assembly of four-wheeled self-propelled vehicles that are designed for use on highways and that have a gross vehicle weight rating of less than 4 536 kg (10,000 pounds), except vehicles capable of operating with no tailpipe emissions and equipped with a battery with a capacity of at least 15 kWh

50 Schedule 1 to the Regulations is amended by adding the following after item 38:
Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO₂e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
Wood Products
39	(1) Production of wood veneer or plywood	Cubic metres of wood veneer and plywood	0.0701	Part 39
	(2) Production of lumber	Cubic metres of lumber	0.0229	Part 39
	(3) Production of the following products: (a) particle board, excluding oriented strand board (b) low, medium or high density composite panels, composed primarily of cellulosic fibers and a bonding system, cured under heat and pressure, including hardboard	Cubic metres of particle board and of panels composed primarily of cellulosic fibers and a bonding system cured under heat and pressure, including hardboard	0.0889	Part 39
Aluminium
40	Aluminium production from alumina	Tonnes of liquid aluminium	1.58	Part 40
41	Production of baked anodes for use in aluminium production from alumina	Tonnes of baked anodes	0.328	Part 41
42	Production of calcined petroleum coke for use in aluminium production from alumina	Tonnes of calcined petroleum coke	0.486	Part 42
43	Production of alumina from bauxite	Tonnes of alumina (Al₂O₃ ) equivalent	Calculated in accordance with section 37 of these Regulations	Part 43
Rubber Products
44	Production of pneumatic tires, not including retreading and other forms of reconditioning	Tonnes of pneumatic tires	0.225	Part 44

51 Schedule 2 of the Regulations is amended by adding the following after section 3:

3.1 The global warming potential applicable for each GHG for the compliance period.

52 Section 8 of Schedule 2 of the Regulations is replaced by the following:

8 The output-based standard for each of the specified industrial activities engaged in at the covered facility.

8.1 If an output-based standard must be calculated for a specified industrial activity engaged in at the covered facility or recalculated under to section 39 of these Regulations, the following information in the annual report for the compliance period for which the standard is calculated,

(a) the quantification, sampling, analysis and measurement methods and the data used to calculate that standard;
(b) if a determination is made under subsection 37(2.1) of these Regulations, the methods for the projections and the projections bearing the stamp and signature of an engineer; and
(c) the method used to attribute the quantity of GHGs to each specified industrial activity or to activities that are not specified industrial activities.

53 Schedule 3 to the Regulations is replaced by the Schedule 3 set out in the schedule to these Regulations.

54 The portion of paragraph 3(n) of Schedule 5 of the Regulations before subparagraph (i) is replaced by the following:

(n) a verification opinion by the verification body containing

Environmental Violations Administrative Monetary Penalties Regulations

55 Division 2 of Part 7 of Schedule 1 to the Environmental Violations Administrative Monetary Penalties Regulations ^{footnote 2} is amended by adding the following in numerical order:
Item	Column 1 Provision	Column 2 Violation Type
9.1	16(6.1)(a)	E

56 Division 2 of Part 7 of Schedule 1 to the Regulations is amended by adding the following in numerical order:
Item	Column 1 Provision	Column 2 Violation Type
13.2	22.1	D

57 Division 2 of Part 7 of Schedule 1 to the Regulations is amended by adding the following in numerical order:
Item	Column 1 Provision	Column 2 Violation Type
14.1	31(2)	D

58 Item 16 of Division 2 of Part 7 of Schedule 1 to the Regulations is replaced by the following:
Item	Column 1 Provision	Column 2 Violation Type
16	36(1)	E
16.1	36(2)	E
16.2	36(3)	E
16.3	36(4)	E
16.4	36(5)	E

59 Division 2 of Part 7 of Schedule 1 to the Regulations is amended by adding the following in numerical order:
Item	Column 1 Provision	Column 2 Violation Type
26.11	45(4)	D

Coming into Force

60 (1) Subject to subsections (2) and (3), these Regulations come into force on the day on which they are registered.

(2) Sections 5 and 6, subsections 2(5), 12(1), 14(1), 23(1) and 24(1), sections 25 and 26, subsection 45(1) and section 46 are deemed to have come into force on January 1, 2023 and apply from that date with respect to the 2023 compliance period and subsequent compliance periods.

(3) Section 1, subsections 2(1), (4), (7) and (9), section 11, subsection 12(2), section 13, subsections 14(2) and (3), sections 15 to 18, subsections 19(1), (2), (4) and (5), sections 20 to 22, subsections 23(2) and (3), 24(2), 28(1) and 29(2), sections 41 to 44, subsections 45(2) and (3), and sections 47 to 50, 53, 55 and 56 come into force on January 1, 2024 and apply with respect to the 2024 compliance period and subsequent compliance periods.

SCHEDULE

(Section 53)

SCHEDULE 3

(Paragraphs 17(2)(a) and (b), 20(2)(a), and 31(1)(a), subparagraph 31(1)(b)(i), subsection 32(1), paragraphs 34(1)(b) and (c) and Schedule 1)

Quantification Requirements

PART 1
Bitumen and Other Crude Oil Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Flaring emissions	CO₂, CH₄ and N₂O
3	Wastewater emissions from
	(a) anaerobic and aerobic wastewater treatment	CO₂, CH₄ and N₂O
	(b) oil-water separators	CH₄
4	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 2
Bitumen and Heavy Oil Upgrading

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions from
	(a) hydrogen production	CO₂
	(b) sulphur recovery	CO₂
	(c) catalyst regeneration	CO₂, CH₄ and N₂O
3	Flaring emissions	CO₂, CH₄ and N₂O
4	Venting emissions from
	(a) process vents	CO₂ and N₂O
	(b) uncontrolled blowdown	CO₂ and N₂O
5	Wastewater emissions from
	(a) anaerobic and aerobic wastewater treatment	CO₂, CH₄ and N₂O
	(b) oil-water separators	CH₄
6	On-site transportation emissions	CO_2, CH₄ and N₂O

PART 3
Petroleum Refining

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Venting emissions from
	(a) process vent	CO₂, CH₄ and N₂O
	(b) asphalt production	CO₂, and CH₄
	(c) delayed coking unit	CH₄
3	Industrial process emissions from
	(a) hydrogen production	CO₂
	(b) catalyst regeneration	CO₂, CH₄ and N₂O
	(c) sulphur recovery	CO₂
	(d) coke calcining	CO₂, CH₄ and N₂O
4	Flaring emissions	CO₂, CH₄ and N₂O
5	Leakage emissions	CH₄
6	Wastewater emissions from
	(a) anaerobic and aerobic wastewater treatment	CO₂, CH₄ and N₂O
	(b) oil-water separators	CH₄
7	On-site transportation emissions	CO_2, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 (1) Direct-only complexity weighted barrels (direct-only CWB) is quantified in accordance with the method outlined in section 2.5 of the directive entitled CAN-CWB Methodology for Regulatory Support: Public Report, published by Solomon Associates in January 2014.

(1.1) When quantifying the direct-only complexity weighted barrels, the emissions and energy use accounted for are those that are associated with the industrial activity set out in paragraph 3(a), column 1 of Schedule 1.

(2) In the method referred to in subsection (1),

(a) the value of “Sales and Exports of Steam and Electricity” is equal to zero;
(b) the value of “EC Reported CO₂e Site Emissions” excludes
- (i) the emissions associated with electricity generated at the covered facility and used for the purpose of the industrial activity set out in paragraph 3(a), column 1 of Schedule 1, prorated based on the energy used for the refinery operation, and
- (ii) the emissions associated with steam generated at the covered facility but not used for the purpose of the industrial activity set out in paragraph 3(a), column 1 of Schedule 1;
(c) the value of “Deemed Indirect CO₂e Emissions from imported electricity”
- (i) includes emissions associated with electricity that is generated and used at the covered facility and used for the purpose of the industrial activity set out in paragraph 3(a), column 1 of Schedule 1, prorated based on the energy used for the refinery operation, and
- (ii) for purchased electricity, is calculated using 0.420 tonnes of CO₂e per megawatt hours of electricity bought;
(d) the value of “Deemed Indirect CO₂e Emissions from imported steam” is equal to zero; and
(e) the value of the “CWB factor” used to calculate hydrogen generation, in all cases, is 5.7.

PART 3.1
Surface mining of oil sands and extraction of bitumen

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Flaring emissions	CO₂, CH₄ and N₂O
3	Leakage emissions	CO₂ and CH₄
3	Wastewater emissions from
	(a) anaerobic and aerobic wastewater treatment	CO₂, CH₄ and N₂O
	(b) oil-water separators	CH₄
5	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 4
Natural Gas Processing

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions from acid gas removal	CO₂
3	Flaring emissions	CO₂, CH₄ and N₂O
4	On-site transportation emissions	CO₂, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 The combined quantity, in cubic metres, of propane and butane set out in paragraph 4(b), column 2, of the table to Schedule 1 is the sum of the quantity of propane, in cubic metres, at a temperature of 15°C and at an equilibrium pressure and the quantity of butane at a temperature of 15°C and at an equilibrium pressure, in cubic metres.

PART 5
Natural Gas Transmission

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Flaring emissions	CO₂, CH₄ and N₂O

DIVISION 2

Quantification of Production

1 (1) Production by the covered facility, expressed in megawatt hours, is the sum of the amounts determined by the following formula for each of the drivers operated by the covered facility:

P_x × L_x× H_x

where

P_x

is the rated brake power of driver “x”, expressed in megawatts;

L_x

is the actual annual average percent load of driver “x”, or, if the actual annual average percent load is unavailable, the percentage determined by the formula:

rpm_avg /rpm_max: where
rpm_avg: is the actual annual average speed during operation of driver “x”, expressed in revolutions per minute, and
rpm_max: is the maximum rated speed of driver “x”, expressed in revolutions per minute;
H_x: is the number of hours during the compliance period that driver “x” was operated; and

(2) The following definitions apply in this section.

driver: means an electric motor, reciprocating engine or turbine used to drive a compressor. (conducteur)
rated brake power: means the maximum brake power of a driver as specified by its manufacturer either on its nameplate or otherwise. (puissance au frein nominale)

PART 6
Hydrogen Gas Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	Flaring emissions	CO₂, CH₄ and N₂O
4	Leakage emissions	CH₄
5	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 7
Cement and Clinker Production

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	On-site transportation emissions	CO₂, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 The quantity of clinker set out in paragraph 7(a), column 2, of Schedule 1 refers only to clinker that is transported out of the facility.

2 The quantity of grey cement and white cement set out in paragraphs 7(b) and (c), column 2, of Schedule 1 refers only to cement produced from clinker that was produced at that facility and that has not been transported out of the facility.

PART 8
Lime Manufacturing

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	On-site transportation emissions	CO₂, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 The quantity of dolomitic lime does not include the dolomitic lime used in the production of speciality lime.

PART 9
Glass Manufacturing

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 10
Gypsum Product Manufacturing

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 11
Mineral Wool Insulation Manufacturing

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 12
Brick Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 13
Ethanol Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 14
Furnace Black Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	Venting emissions	CO₂, CH₄ and N₂O
4	Leakage emissions	CH₄
5	Industrial product use emissions	SF₆ and PFC
6	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 15
2–methylpentamethylenediamine (MPMD) Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	Industrial product use emissions	SF₆ and PFC
4	Flaring emissions	CO₂, CH₄ and N₂O
5	Leakage emissions	CH₄
6	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 16
Nylon Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 17
Petrochemicals Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	Venting emissions	CO₂, CH₄ and N₂O
4	Flaring emissions	CO₂, CH₄ and N₂O
5	Leakage emissions	CH₄
6	Wastewater emissions	CO₂, CH₄ and N₂O
7	Industrial product use emissions	SF₆ and PFC
8	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 18
Vaccine Production

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial product use emissions	SF₆
3	On-site transportation emissions	CO₂, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 Production is quantified at the end of the formulation step of the manufacturing process, in litres of vaccine, determined by the formula:

: where:
A: is the capacity of each tank “i” that is used to combine ingredients at that step, expressed in litres;
B: is the number of batches produced in tank “i”; and
i: is the i^th tank where “i” goes from 1 to n where n is the total number of tanks used to combine ingredients for that step.

PART 19
Scrap-based steel production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions from
	(a) electric arc furnace	CO₂
	(b) argon-oxygen decarburization vessel	CO₂
	(c) ladle furnace	CO₂
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 20
Integrated Steel Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions from
	(a) basic oxygen furnace	CO₂
	(b) coke oven battery	CO₂
	(c) direct reduction furnace	CO₂
	(d) electric arc furnace	CO₂
	(e) blast furnace	CO₂
	(f) ladle furnace	CO₂
	(g) argon-oxygen decarburization vessel	CO₂
3	Wastewater emissions	CO₂, CH₄ and N₂O
4	Industrial product use emissions	SF₆ and PFC
5	On-site transportation emissions	CO₂, CH₄ and N₂O
6	Leakage emissions from coal storage	CH₄

PART 21
Iron Ore Pelletizing

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions (induration furnace)	CO₂
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 22
Metal Tube Manufacturing

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 23
Base Metal Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄, and N₂O
2	Industrial process emissions from
	(a) lead production	CO₂
	(b) zinc production	CO₂
	(c) copper and nickel production	CO₂
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 24
Potash Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 24.1
Production of Evaporated Salt

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 25
Coal Mining

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Leakage emissions from
	(a) coal storage	CH₄
	(b) underground coal mining	CH₄
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 26
Production of Metals or Diamonds

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 27
Char Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 28
Activated Carbon Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 29
Nitrogen-based Fertilizer Production

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions from
	(a) nitric acid	N₂O
	(b) ammonia steam reforming	CO₂
3	On-site transportation emissions	CO₂, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 The quantity of urea liquor does not include the urea liquor used in the production of granular urea.

PART 30
Industrial Potato Processing

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Wastewater emissions	CO₂, CH₄ and N₂O
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 31
Industrial Oilseed Processing

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Wastewater emissions	CO₂, CH₄ and N₂O
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 32
Alcohol Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Wastewater emissions	CO₂, CH₄ and N₂O
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 33
Wet Corn Milling

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Wastewater emissions	CO₂, CH₄ and N₂O
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 34
Citric Acid Production

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 35
Sugar Refining

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 35.1
Production of Malt

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Wastewater emissions	CO₂, CH₄ and N₂O
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 36
Pulp and Paper Production

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions from
	(a) boiler, thermal oxidizer, direct-fired turbine, engine, gasifier or any other combustion device that generates heat, steam or energy	CO₂, CH₄ and N₂O
	(b) recovery boiler	CO₂, CH₄ and N₂O
	(c) lime kiln	CO₂
	(d) lime kiln	CH₄ and N₂O
2	Industrial process emissions: addition of carbonate compound into a lime kiln	CO₂
3	Wastewater emissions	CO₂, CH₄ and N₂O
4	On-site transportation emissions	CO_2, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 (1) Production by the covered facility is quantified in tonnes of finished product or tonnes of specialty product, as follows:

(a) in the case of pulp, including dissolving pulp for viscose,
- (i) if the moisture content exceeds 10%, the weight of the pulp is adjusted so that its moisture content does not exceed 10%, and
- (ii) if the moisture content is equal to or less than 10%, the weight of the pulp without adjustment; and
(b) in the case of a finished product or specialty product referred to in subsection (3) derived directly from pulp or the pulping process, the weight of the product or, if it has been machine dried, its weight after it has been dried.

(2) A finished product referred to in paragraph (1)(b) does not include pulping liquor, wood waste, non-condensable gases, sludge, tall oil, turpentine, biogas, steam, water or products that are used in the production process.

(3) For the purposes of paragraph (1)(b), a specialty product means abrasive paper base, food grade grease resistant paper, packaging waxed paper base, paper for medical applications, napkin paper for commercial use, towel paper for commercial or domestic use, bath paper for domestic use and facial paper for domestic use.

PART 37
Main Assembly of Vehicles

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial product use emissions	HFC
3	On-site transportation emissions	CO₂, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 Production is the number of vehicles referred to in item 37 of column 1, of Schedule 1 that are assembled during the compliance period.

PART 38
Electricity Generation

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion	CO₂, CH₄, N₂O
2	Leakage emissions from coal storage	CH₄
3	Industrial process emissions from acid gas scrubbers and acid gas reagent	CO₂
4	Industrial product use emissions from
	(a) electrical equipment	SF₆ and PFC
	(b) cooling units	HFC
5	On-site transportation emissions	CO₂, CH₄ and N₂O

DIVISION 2
Quantification of Production — Main Industrial Activity

1 (1) Subject to section 2, if a unit uses only one fossil fuel to generate electricity, production of electricity must be quantified in Gigawatt hours of gross electricity generated by the unit, measured at the electrical terminals of the generators of each unit using meters that comply with the requirements set out in subsection 31(2) of these Regulations.

(2) Subject to section 2, if a unit uses a mixture of fossil fuels or a mixture of biomass and fossil fuels to generate electricity, the gross electricity generated by the unit is to be determined separately for the gaseous fuels, liquid fuels and solid fuels in accordance with the following formula and expressed in Gigawatt hours:

where

G_U

is the gross quantity of electricity generated by the unit during a compliance period, as measured at the electrical terminals of the generators of the unit using meters that comply with the requirements set out in subsection 31(2) of these Regulations;

HFF_k

is determined in accordance with the following formula, calculated separately for gaseous fuels, liquid fuels and solid fuels type “k”:

: where
QFF_j: is the quantity of gaseous, liquid or solid fuel, as the case may be, type “j” combusted in the unit to generate electricity during the compliance period, determined in accordance with subsection (3),
HHV_j: is the higher heating value of the gaseous, liquid or solid fuel, as the case may be, type “j” combusted in the unit, determined in accordance with Quantification Methods, and
j: is the j^th fossil fuel type combusted in the unit, where “j” goes from 1 to m and where m is the number of types of gaseous, liquid or solid fuel combusted, as the case may be, combusted; and

HB

is determined in accordance with the formula

: where:
QB_i: is the quantity of biomass fuel type “i” combusted in the unit to generate electricity during the compliance period, determined in accordance with the subsection (3),
HHV_i: is the higher heating value for the biomass fuel type “i” combusted in the unit, is determined in accordance with Quantification Methods, and
i: is the i^th biomass fuel type combusted in the unit, where “i” goes from 1 to n and where n is the number of types of biomass fuels combusted.

(3) The quantity of fuel for QFF_j or QB_i is determined on the following basis:

(a) for a solid fuel, the mass of the fuel combusted, on a wet or dry basis, expressed in tonnes and measured by a measuring device;
(b) for a liquid fuel, the volume of the fuel combusted, expressed in kL and measured using a flow meter; and
(c) for a gaseous fuel, the volume of the fuel combusted, expressed in standard cubic metres and measured using a flow meter.

2 If a combustion engine unit and a boiler unit share the same steam turbine, the quantity of gross electricity generated by a given unit is determined by the formula

G_ce + G_s – G_ext

where

G_ce

is the gross quantity of electricity that is generated by the generators of the combustion engines in a combustion engine unit that shares a steam turbine with a boiler unit, in the calendar year, expressed in Gigawatt hours, as measured at the electrical terminals of the generators of the combustion engines using meters that comply with the requirements set out in subsection 31(2) of these Regulations, if the given unit for which the electricity is being quantified is a combustion engine unit, or equal to zero, if the given unit for which the electricity is being quantified is a boiler unit;

G_s

is the gross quantity of electricity that is generated by the generators of the shared steam turbine in the calendar year, expressed in Gigawatt hours, as measured at the electrical terminals of the generators of the shared steam turbine using meters that comply with the requirements set out in subsection 31(2) of these Regulations; and

G_ext

is the quantity of electricity that is generated by the unit other than the given unit for which the electricity is being quantified, in the calendar year, expressed in Gigawatt hours and that is determined by the formula

: where
G_s: is the gross quantity of electricity that is generated by the generators of the shared steam turbine in the calendar year, expressed in Gigawatt hours, as measured at the electrical terminals of the generators of the shared steam turbine using meters that comply with the requirements set out in subsection 31(2) of these Regulations,
t: is the t^th hour, where “t” goes from the number 1 to x and where x is the total number of hours during which the generators of the shared steam turbine generated electricity in the calendar year,
j: is the j^th external heat stream, originating from the other unit where “j” goes from the number 1 to m and where m is the total number of external heat streams that contributed to the electricity generated by the generators of the shared steam turbine of the unit,
h_ext,j: is the average specific enthalpy of the j^th external heat stream, originating from the other unit that contributed to the electricity generated by the generators of the shared steam turbine, expressed in gigajoules/tonne, during period “t” and must be based on the measurement of the temperature and pressure of that heat stream and determined using a continuous measuring device,
M_ext,j: is the mass flow of the j^th external heat stream originating from the other unit that contributed to the electricity generated by the generators of the shared steam turbine, expressed in tonnes, during period “t”, determined using a continuous measuring device,
k: is the k^th internal heat stream originating from the given unit, where “k” goes from the number 1 to l and where l is the total number of heat streams that originated from the combustion of fuel in the unit and that contributed to the electricity generated by the generators of the shared steam turbine,
h_int,k: is the average specific enthalpy of the k^th internal heat stream originating from the given unit and having contributed to the electricity generated by the generators of the shared steam turbine, expressed in GJ/tonne, during period “t” and must be based on the measurement of the temperature and pressure of that heat stream and determined using a continuous measuring device, and
M_int,k: is the mass flow of the k^th internal heat stream originating from the given unit that contributed to the electricity generated by the generators of the shared steam turbine, expressed in tonnes, during period “t”, determined using a continuous measuring device.

DIVISION 3
Secondary Industrial Activity – Quantification of Production

3 If a covered facility uses only one fossil fuel to generate electricity, production of electricity is quantified in Gigawatt hours of gross electricity generated through the use of fossil fuels.

4 (1) If a covered facility uses a mixture of fossil fuels or a mixture of biomass and fossil fuels to generate electricity, the gross electricity generated by the facility is to be determined separately for the gaseous fuels, liquid fuels and solid fuels in accordance with the following formula and expressed in Gigawatt hours:

where

G_U

is the gross quantity of electricity generated by the covered facility during the compliance period, expressed in Gigawatt hours;

HFF_k

is determined in accordance with the following formula, calculated separately for gaseous fuels, liquid fuels and solid fuels type “k”:

: where
QFF_j: is the quantity of gaseous, liquid or solid fuel, as the case may be, type “j” combusted in the facility for electricity generation during the compliance period, determined under subsection (2) and in accordance with Quantification Methods,
HHV_j: is the higher heating value of the gaseous, liquid or solid fuel, as the case may be, type “j” combusted in the facility for electricity generation determined in accordance with Quantification Methods, and
j: is the j^th fossil fuel type combusted in the facility, where “j” goes from 1 to m and where m is the number of types of gaseous, liquid or solid fuels combusted, as the case may be; and

HB

is determined in accordance with the formula

: where
QBi: is the quantity of biomass fuel type “i” combusted in the facility for electricity generation during the compliance period, determined in accordance with subsection (2) and with Quantification Methods,
HHVi: is the higher heating value for each biomass fuel type “i” combusted in the facility for electricity generation in accordance with Quantification Methods, and
i: is the i^th biomass fuel type combusted in the facility, where “i” goes from 1 to n and where n is the number of types of biomass fuels combusted.

(2) The quantity of fuel for QFF_j and QB_i is determined on the following basis:

(a) for a solid fuel, the mass of the fuel combusted, on a wet or dry basis, expressed in tonnes and measured in accordance with Quantification Methods;
(b) for a liquid fuel, the volume of the fuel combusted, expressed in kL and measured in accordance with Quantification Methods; and
(c) for a gaseous fuel, the volume of the fuel combusted, expressed in standard cubic metres and measured in accordance with Quantification Methods.

PART 39
Production of wood products

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	On-site transportation emission	CO₂, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 (1) The quantity of wood veneer does not include wood veneer used in the production of plywood.

(2) The quantity of wood veneer and plywood refers only to wood veneer and plywood that will not undergo an additional transformation at the facility.

2 The quantity of lumber produced refers only to lumber that will not undergo an additional transformation at the facility.

3 The quantity of particle board and of panels composed primarily of cellulosic fibers and a bonding system cured under heat and pressure, including hardboard, is quantified after they are cured under heat and pressure.

PART 40
Aluminium production from alumina

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions from
	(a) pre-baked anode consumption	CO₂
	(b) Søderberg electrolysis cells	CO₂
	(c) anode effects	PFC
	(d) carbonate use	CO₂
3	Industrial product use emissions	SF₆ and HFC
4	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 41
Production of baked anodes — Aluminium

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 42
Production of calcined petroleum coke — Aluminium

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial process emissions	CO₂
3	Industrial product use emissions	HFC
4	On-site transportation emissions	CO₂, CH₄ and N₂O

PART 43
Production of alumina from bauxite

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial product use emissions	HFC
3	On-site transportation emissions	CO₂, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 The production is quantified, in tonnes of alumina (Al₂O₃) equivalent determined by the following formula:

A x 0.6536: where
A: is the quantity of alumina hydrate produced at the precipitation step, expressed in tonnes.

PART 44
Production of pneumatic tires

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types
Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O
2	Industrial product use emissions	HFC
3	Wastewater emisssions	CO₂, CH₄, and N₂O
4	On-site transportation emissions	CO₂, CH₄ and N₂O

DIVISION 2
Quantification of Production

1 The quantity of pneumatic tires does not include solid tires.

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Issues: Climate change poses an urgent global threat, with impacts and costs projected to increase over time if left unchecked. Under the Paris Agreement, Canada has committed to reduce greenhouse gas (GHG) emissions by 40% to 45% below 2005 levels by 2030. In order to help address and mitigate the impacts of climate change, meet Canada’s emissions reduction target under the Paris Agreement and achieve net-zero emissions by 2050, a number of GHG emissions reduction measures have been developed, including putting a price on carbon pollution that will reach $170 per tonne of carbon dioxide equivalent (CO₂e) in 2030. As part of the Pan-Canadian Approach to Pricing Carbon Pollution, Canada put in place the Output-Based Pricing System (OBPS) for large emitters. To ensure the OBPS continues to contribute to Canada’s GHG reduction targets while mitigating competitiveness impacts and carbon leakage risks due to carbon pollution pricing, amendments to the Output-Based Pricing System Regulations (the Regulations) are required.

Description: The objective of the federal OBPS is to put a price on carbon pollution that creates an incentive for covered facilities to reduce emissions per unit of output, while continuing to mitigate competitiveness impacts and carbon leakage risks. The Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations (the amendments) modify the Regulations by introducing a 2% fixed annual percentage reduction (tightening rate) to most output-based standards (OBSs) from 2023 onwards, such that the OBPS will continue to meet its objective by maintaining a marginal price on emissions. For sectors that are considered at very high risk of competitiveness impacts and of carbon leakage resulting from carbon pricing, the amendments apply an adjusted tightening rate of 1% from 2023 onwards. The amendments also add new OBSs and update current OBSs and make changes to improve implementation, ensure accurate reporting, and streamline voluntary participation.

Cost-benefit statement: The quantified benefits and costs presented in the regulatory analysis are attributable to both the amendments presented here and the Order Amending Schedule 4 to the Greenhouse Gas Pollution Pricing Act (together referred to as the set of amendments), and they are based on the scope of application of the OBPS at the time of publication of the amendments. Between 2023 and 2032, the cumulative GHG emissions reductions attributable to the set of amendments are estimated to be around 3.3 million tonnes (megatonnes or Mt) of CO₂e. The Department of the Environment (the Department) used its updated schedule of social cost of greenhouse gases (SC-GHG) emissions to monetize the benefits of GHG emissions reductions. This resulted in estimated societal benefits of $910 million. Costs associated with the set of amendments could lower Canadian household welfare by $270 million. Overall, the set of amendments is expected to result in a net benefit of $640 million. The amendments are being made to continue to maintain a marginal price on emissions and ensure the OBPS is national in scope and can apply anywhere in Canada if required.

Issues

Greenhouse gas (GHG) emissions are significantly contributing to a changing climate. Climate change poses an urgent global threat, with impacts and costs projected to increase over time if left unchecked. Without action to reduce GHG emissions, the impacts of climate change are expected to worsen as the global average surface temperature becomes warmer. Changes in temperature and precipitation can impact natural habitats, agriculture and food supplies, and rising sea levels can threaten coastal communities.

Recognizing the need for climate action, the Government of Canada announced the Pan-Canadian Approach to Pricing Carbon Pollution (the Pan-Canadian Approach) in October 2016, which put carbon pricing at the centre of Canada’s climate action. The Pan-Canadian Approach sets out minimum national stringency standards, referred to as the federal benchmark, which all carbon pricing systems across Canada must meet. The federal carbon pollution pricing backstop system (the federal backstop) applies in provinces and territories that do not have carbon pricing systems that meet the federal benchmark (called “backstop jurisdictions”). The federal backstop, introduced in 2019, contains two parts: a regulatory charge on fossil fuels (the fuel charge) and a regulatory trading system for industrial facilities in sectors at significant risk of carbon leakage and competitiveness impacts, known as the Output-Based Pricing System (OBPS).

Since 2016, Canada has increased its climate ambition and, in 2021, committed to reduce GHG emissions by 40% to 45% below 2005 levels by 2030 and to reach net-zero emissions by 2050. To ensure carbon pollution pricing remains a strong contributor to GHG reductions, the Government of Canada announced in 2021 that the price on carbon pollution would increase to $65 per tonne of carbon dioxide equivalent (CO₂e) in 2023 and increase by $15 per calendar year until it reaches $170 per tonne of CO₂e in 2030.

This carbon price trajectory is part of the strengthened benchmark announced in summer 2021, along with increased stringency of other criteria. The Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations (the amendments) are required to ensure the OBPS remains aligned with the federal benchmark and continues to deliver GHG reductions, while mitigating competitiveness impacts and carbon leakage risks. Maintaining the effectiveness of the OBPS by ensuring net demand for credits will result in a strong marginal price signal that is in alignment with the federal benchmark.

Background

In December 2015, the international community, including Canada, adopted the Paris Agreement, an accord intended to reduce 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 commitments made under the Paris Agreement, Canada pledged to reduce national GHG emissions by 30% below 2005 levels by 2030.

On July 12, 2021, the Minister of the Environment (the Minister) formally submitted Canada’s enhanced nationally determined contribution to the United Nations, committing Canada to reduce national GHG emissions by 40% to 45% below 2005 levels by 2030. Canada has also committed to achieving net-zero GHG emissions by 2050 under the Canadian Net-Zero Emissions Accountability Act. To meet these obligations, the federal government is implementing a series of measures, including continuing to put a price on carbon pollution.

The Pan-Canadian Approach, published in 2016, is one of the four main pillars of the Pan-Canadian Framework on Clean Growth and Climate Change (PCF). Building on the actions in the PCF, the 2030 Emissions Reduction Plan (ERP) provides a roadmap to how Canada will meet its enhanced Paris Agreement target to reduce GHG emissions by 40% to 45% from 2005 levels by 2030. The ERP, published in March 2022, is the first plan issued under the Canadian Net-Zero Emissions Accountability Act. Carbon pollution pricing is a central pillar of the PCF and the ERP.

Under the Government of Canada’s approach to pricing carbon pollution, provinces and territories have the flexibility to implement a carbon pricing system that makes sense for their circumstances, either an explicit price-based system or a cap-and-trade system, provided that the system meets minimum national stringency criteria, referred to as the federal benchmark. The federal benchmark sets the criteria that all systems must meet to ensure they are comparable and effective in reducing GHG emissions.

In August 2021, the Government of Canada updated the federal benchmark for the 2023–2030 period, including the minimum national price on carbon pollution that will increase by $15 per tonne of CO₂e each year starting in 2023 through to 2030.^{footnote 3} The updated benchmark also strengthened criteria on coverage, enhanced rules for offset programs and offset credits, included additional requirements for public reporting and disallowed measures that directly offset, reduce or negate the price signal sent by carbon pricing. To provide certainty to households and businesses, annual assessments were replaced with a multi-year assessment completed in fall 2022, for the entire 2023–2030 period. Provincial and territorial carbon pricing systems assessed as meeting the updated federal benchmark will apply until at least the end of 2026 when the federal government conducts an interim assessment of provincial and territorial systems to confirm they continue to meet the benchmark for the 2027–2030 period. If significant modifications are introduced before 2027, the system will be reassessed. Similarly, where the backstop applies in 2023, it will remain in place until at least the end of 2026. By 2026 the federal government will also engage with provinces, territories, and Indigenous organizations in an interim review of carbon pricing in Canada and of the benchmark criteria to ensure it continues to meet its objective of ensuring comparable and effective carbon pricing systems across Canada.

The Greenhouse Gas Pollution Pricing Act (the Act), enacted on June 21, 2018, establishes the framework for the federal backstop system consisting of two parts: a regulatory charge on fossil fuels (fuel charge) under Part 1 of the Act, and a regulatory trading system for industry, known as the OBPS, under Part 2 of the Act. The federal backstop, which can include the fuel charge, the OBPS, or both, applies in any jurisdiction that requests it or does not have a carbon pricing system that meets the federal benchmark. In 2023, the OBPS applies in Manitoba, Prince Edward Island, Yukon, and Nunavut.

The Output-Based Pricing System Regulations (the Regulations) were published in the Canada Gazette, Part II, on July 10, 2019. The federal OBPS is designed to put a price on carbon pollution, creating an incentive for industrial facilities from sectors at significant risk of carbon leakage and competitiveness impacts to reduce their emissions per unit of output. Carbon leakage occurs when production and investment shift to jurisdictions with less stringent carbon pricing, weakening emissions reductions at the global level, while reducing economic activity in the jurisdiction with more stringent carbon pricing. Adverse competitiveness impacts, such as a loss of global market share, can occur when the economic situation faced by facilities changes, for example, due to an increase in production costs from carbon pricing. These competitiveness impacts may lead to carbon leakage.

The Regulations define the facilities to which the OBPS applies (covered facilities) and specify OBSs for certain industrial activities that are set on an emissions per unit of output (emissions intensity) basis. Covered facilities generally do not pay the fuel charge on fuels that they use at their facilities; instead, they are required to provide compensation on an annual basis for any GHG emissions exceeding their respective facility emissions limit. A covered facility’s emissions limit, which is measured in tonnes of CO₂e, is determined by summing the facility’s production (usually expressed in units of output) for each specified industrial activity multiplied by the applicable OBS. A covered facility with GHG emissions below its limit receives surplus credits issued by the Minister for the difference between its GHG emissions and its limit. These surplus credits can be sold or used to meet future compensation obligations.

Starting with the 2022 compliance period, each covered facility must provide a minimum of 25% of their compensation obligation through payment of the excess emissions charge to the Receiver General for Canada. The remaining compensation obligation can be made by excess emissions charge payments or the use of compliance units, each representing one tonne of CO₂e or a combination of those two methods. Compliance units are either (i) surplus credits that have been issued by the Minister to the covered facility providing compensation or that have been acquired through trading with other covered facilities; (ii) eligible provincial or territorial offset credits formally recognized by the Minister under the Regulations as compliance units; or (iii) federal offset credits issued by the Minister.^{footnote 4}

Covered facilities in federal backstop jurisdictions

Mandatory covered facilities are those located in backstop jurisdictions that emit 50 kilotonnes (kt) or more of CO₂e per year and carry out an activity listed in Schedule 1 to the Regulations as their primary activity. Other facilities located in a backstop jurisdiction may voluntarily request designation to participate in the OBPS. Each opt-in application is considered on its merits and on a case-by-case basis. The key considerations taken into account when assessing applications are outlined in an updated version of the Policy Regarding Voluntary Participation in the Output-Based Pricing System (the Opt-in Policy). They include that the facility emits or, in the case of a new, retrofitted, or expanded facility, is projected to emit a minimum of 10 kt of CO₂e per year and is engaged in at least one of the industrial activities listed in Schedule 1 of the Regulations or at least one of the additional industrial activities on the list of additional industrial activities published by the Department. In 2023, there are 37 covered facilities in the backstop jurisdictions where the OBPS applies. There are 7 mandatory covered facilities and 23 voluntary facilities in Manitoba, 1 mandatory facility in Prince Edward Island, 1 mandatory facility in Yukon, and 5 mandatory facilities in Nunavut.

Output-based standards

Output-based standards are the emissions-intensity performance standards for specific activities covered under the OBPS, expressed as a quantity of GHG emissions per unit of output for a given product or activity. These standards are, for the most part, set as a percentage of the production-weighted average emissions intensity of all large emitter facilities producing similar products across Canada. To establish the OBSs, emissions reduction factors are applied to the production weighted average emissions intensities. The emissions reduction factor is set at 80%, 90% or 95%, depending on the risk of carbon leakage and competitiveness impacts faced by the sector. In addition, OBSs were adjusted for sectors with process emissions constituting 30% or more of total GHG emissions at the sector level. All else being equal, a lower emissions reduction factor results in a more stringent OBS.

Most OBSs listed in Schedule 1 to the Regulations are numeric. For existing numeric OBSs, the production weighted average emissions intensity of a given industrial activity is calculated using the emissions and production information from all facilities in Canada undertaking the industrial activity and that emitted 50 kt or more of CO₂e per year during the 2014–2016 period. Some OBSs are facility specific and are referred to as calculated OBSs. These OBSs are calculated using emissions and production information for the respective facility for specified reference years.

Assessing competitiveness and carbon leakage risks

The Department categorizes sectors as emissions intensive and trade exposed (EITE) based on their level of risk of carbon leakage and adverse competitiveness impacts. The results from these analyses are used to determine the emissions reduction factor used to set an OBS. There are two parts to this metric: economic emissions intensity (i.e. carbon costs per unit of gross value added of a sector) and trade exposure (i.e. exposure to import and export competition in a sector).

The Department has developed a three-phased approach to provide an assessment of potential carbon leakage and competitiveness risks due to the application of carbon pricing under the OBPS. In Phase 1, historical data, primarily from national public data sources, is used to assess which sectors exceed EITE thresholds. Phase 2 involves the same analysis but estimates EITE levels using projections from the Department’s EC-Pro model.^{footnote 5} Phase 3 considers additional information relevant to the assessment of the risks of carbon leakage and adverse competitiveness impacts due to carbon pricing. In particular, this includes analysis of the direct costs from carbon pricing relative to financial data for a substantive portion of the facilities of a sector (i.e. facility carbon costs per unit of facility revenue).^{footnote 6}

Objective

The objective of the amendments is to maintain the effectiveness of the OBPS so that it continues to contribute to Canada’s GHG emissions reduction targets while mitigating competitiveness impacts and carbon leakage risks from carbon pricing.

Description

The amendments make modifications to the Regulations to add an annual tightening rate to most OBSs, to align with the strengthened federal benchmark and to help ensure the OBPS continues to contribute to Canada’s GHG emissions reduction targets while mitigating the risks of carbon leakage and competitiveness impacts. It also introduces new OBSs and revises existing OBSs in certain limited circumstances, enabling the OBPS to function effectively as a backstop and apply in any jurisdiction in Canada as required. Furthermore, the amendments enable the harmonization of quantification methods for GHG emissions between the OBPS and the federal Greenhouse Gas Reporting Program (GHGRP); improve regulatory implementation by recognizing additional industrial activities; streamline voluntary participation; provide an exemption for remote electricity generation facilities that generate electricity from liquid or gaseous fuels for distribution to remote communities; modify the method to calculate site-specific OBSs; clarify requirements for the recognition and remittance of a unit or a credit as a compliance unit and the information to be provided on their remittance; and make changes to rules related to reporting and verification. Finally, the amendments apply to covered facilities and modify the Regulations, based on the review by the Department, as described below.

Tightening rates

The amendments introduce tightening rates to the OBSs. A tightening rate is a fixed annual percentage reduction to a standard (i.e. a fixed annual increase in the stringency). OBSs will continue to decline at the respective annual tightening rate with no end date. The amendments modify the formula to calculate the facility’s emissions limit by incorporating an annual 2% tightening rate to most OBSs from 2023 onwards. In sectors at very high risk of competitiveness impacts and carbon leakage resulting from carbon pricing, an annual 1% tightening rate applies to OBSs from 2023 onwards.^{footnote 7} The 1% tightening rate applies to cement, lime, petrochemicals, iron and steel and certain aluminum, and organic basic chemicals standards. No tightening rate is applied to the generation of electricity using fossil fuels, whether the electricity is generated at an industrial facility or at an electricity generation facility.

Output-based standards

New output-based standards

The amendments add 12 industrial activities to the existing activities listed in Schedule 1 to the Regulations and prescribe their OBSs. These additional OBSs have been developed for activities where three or more facilities in Canada have emissions of 10 kt of CO₂e or more per year per facility. The national production weighted average emissions intensities were set using data from the 2017–2019 reference years for most standards and employed an approach that was generally consistent with how existing standards have been set. The standards were calculated with emissions quantified using the updated values for global warming potential (GWP) in Schedule 3 to the Act, where the change in GWPs had a material (greater than 1%) impact on the respective standard, consistent with the approach to revising existing standards described below. This affected two standards: the standard for surface mining of oil sands and extraction of bitumen, and the standard for aluminum production from alumina.

Standards are assigned an emissions reduction factor of 80%, 90% or 95% of the national production weighted average emissions intensity, depending on the risk level of the sector in the competitiveness and carbon leakage risk assessment and the proportion of industrial process emissions. The standards and the corresponding results of the risk assessments are detailed in the regulatory analysis section below.

The current exclusion of methane emissions from leakage and venting emissions that applies to most oil and gas standards under the Regulations was not extended to apply to the standard for surface mining of oil sands and extraction of bitumen; therefore, area fugitive emissions from this activity are included in the standard.

Review of existing output-based standards

The amendments make changes to some existing OBSs, including the revision of the urea liquor standard into a standard for granular urea and a standard for urea liquor. The introduction of a distinct standard for granular urea requires a revision to the existing urea liquor standard so that it no longer includes the additional emissions associated with producing granular urea. These standards were set based on data for the reference years used to set the existing urea liquor standard and both standards received the emissions reduction factor of 90% that was applied to the existing urea liquor standard.

Additionally, the amendments update the activity definition for automotive manufacturing to exclude the production of zero-emission vehicles. The amendments also update the activity description related to the production of metal or diamonds set out in item 26 of Schedule 1 to the Regulations. This update clarifies the description so that the activity applies to the mining and milling of a product instead of to the mining or milling of a product.

As a result of updates to GWPs in Schedule 3 to the Act, the amendments update the OBSs for potato processing and production of nitric acid. For these standards, the change in GWP values resulted in a material change in an OBS, defined as plus or minus 1% of the value of the OBS, as detailed in the “Regulatory analysis” section.

Reducing administrative burden

The amendments remove detailed GHG emissions quantification methods from Schedule 3 to the Regulations. Those quantification methods are now specified in the Quantification Methods for the Output-Based Pricing System Regulations (Quantification Methods), a technical document incorporated by reference into the Regulations. This will allow the Minister to continue to update the specified methods on an ongoing basis, as required, to incorporate technical updates and to harmonize the GHG quantification methods with the GHGRP, where possible.

Section 176 of the Act requires the person responsible for a covered facility to notify the Minister of any error or omission within five years of the submission of an annual report. The amendments remove the obligation to submit a corrected report when any error or omission in an annual report is identified by the person responsible. Instead, the corrected report accompanied by its verification report will only be required when the error or omission identified in the notice would have constituted a material discrepancy if the error had been identified during the verification of the annual report. The deadline to submit the corrected report is extended from 90 days from the date of the submission of the notice to the Minister to 120 days from that date. The Minister maintains the ability to determine if a corrected report is necessary in other circumstances.

Improving implementation

Recognizing additional industrial activities

The amendments define an additional industrial activity as an industrial activity that is not set out in column 1 of Schedule 1, that is recognized by the Minister as being from a sector at significant risk of competitiveness impacts and carbon leakage resulting from carbon pricing. The amendments require all covered facilities engaged in additional industrial activities to include these activities in the determination of their emissions limit. Any additional industrial activity newly recognized by the Minister will only be included in the determination of a covered facility’s emissions limit for the compliance period that follows the calendar year in which the additional industrial activity is recognized.

Streamlining voluntary participation

The amendments make several changes that impact the opt-in process. These include setting the start of the first compliance period to January 1 of the calendar year after the year in which the Minister designated the facility as a covered facility. Some opt-in facilities must calculate their OBS using site-specific information that needs to be submitted as part of their opt-in application. Changes to the calculated OBS allow these opt-in facilities to submit this information as part of their annual reports, in the same manner as other facilities that calculate their OBSs. This contributes to streamlining the opt-in process. Other changes to calculated OBSs include removing emissions from non-specified industrial activities from the OBS calculation in certain circumstances. This enables the Minister to broaden opt-in eligibility to facilities engaged in an additional industrial activity as a secondary activity, while ensuring the calculation of the OBS applicable to the secondary activity is representative of the emissions associated with this activity. The amendments also add provisions related to the cancellation of designations, so that when a person responsible for a facility requests that its designation as a covered facility be cancelled, it will be effective on December 31 of the year in which the decision to cancel the designation is made.

Calculated output-based standards

The amendments change how calculated OBSs are determined. This includes taking carbon capture and storage into consideration, clarifying how thermal energy transfers are calculated, and removing emissions from non-specified industrial activities from the OBS calculation in certain circumstances. The amendments also change the reference years used for calculated OBSs to align the reference years used to calculate an OBS for activities listed in Schedule 1 to the Regulations, where required, with those used to calculate an OBS for additional industrial activities. The amendments also require the use of projections for new activities engaged in at a covered facility where no data is available for the reference years. After three years of production, the covered facility will be required to recalculate the applicable OBS using the actual emissions at the facility during the three preceding years. Where it is necessary to attribute GHG emissions between activities, the amendments require that the method applied be rigorous, objective, based on sound engineering principles and be used for each reference year. No quantity of GHGs may be attributed to more than one activity.

Accurate reporting

Verification

The Regulations establish the requirements to be met for the verification of annual reports by third parties. This includes that verification bodies must be accredited to ISO Standard 14065 entitled Greenhouse gases — Requirements for greenhouse gas validation and verification bodies for use in accreditation or other forms of recognition. In addition, verification bodies must conduct the verification in accordance with ISO Standard 14064-3 published by the International Organization for Standardization. These ISO standards are updated from time to time. The amendments incorporate ISO Standard 14065, as amended from time to time. Despite this, if ISO Standard 14065 is amended, the amendments allow for a transition period during which the previous version of that standard may be complied with for a period of four years beginning on the day on which the amended version is published so that verification bodies have time to obtain accreditation to the updated ISO Standard 14065. The amendments also allow verification bodies to conduct the verification in accordance with the version of 14064-3 set out in their accreditation to allow for transitions to newer versions of the standard.

The amendments also clarify when a site visit must be made to a covered facility. The person responsible for a covered facility must ensure that their covered facility is visited by an accredited verification body if two calendar years have passed since a verification body has visited the covered facility.

A materiality threshold is the threshold at which errors or omissions could influence the decision of the intended users. The amendments change the materiality threshold for GHG emissions from 8% to 5% for covered facilities that emit less than 50 kt of CO₂e per year. The table below shows the breakdown of the materiality thresholds for GHG emissions.

Table 1: Materiality threshold for GHG emissions
Annual covered facility GHG emissions	Past	Current
Less than 50 kt of CO₂e	8%	5%
At least 50 but less than 500 kt of CO₂e	5%	No change
At least 500 kt of CO₂e	2%	No change

Correction of errors and omissions

The amendments also require the person responsible for the covered facility to correct errors and omissions identified by a verification body during the verification of the annual report, prior to submitting the annual report, if possible.

Measuring devices

The amendments introduce a set of requirements related to installation, maintenance, operation, and calibration of measuring devices used in the quantification of GHGs. These new requirements are similar to the existing requirements for measuring devices used in the quantification of production from industrial activities with one notable difference. They specify that, where applicable, requirements in the Quantification Methods take precedence. For example, equipment and calibration required through the Quantification Methods would supersede the calibration set out in the new provision. Both the GHG and production rule give precedence to manufacturers’ specifications over industry standards.

The amendments also remove the requirement that meters used in the quantification of electricity generated by an electricity generation facility must comply with the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations. Instead, these meters must meet the same requirements as any other measuring devices used in the quantification of production.

Other amendments

In addition to the changes discussed above, the amendments also

amend the criteria for being a covered facility to reflect the removal of the name of Saskatchewan from Part 2 of Schedule 1 to the Act, as of January 1, 2023;
exempt remote electricity generation facilities primarily engaged in the generation of electricity using liquid or gaseous fuels for remote communities from the definition of a covered facility in section 169 of the Act;
fix the start of the first compliance period to January 1 of the calendar year after the year in which the facility meets the criteria for being a covered facility, i.e. a mandatory facility;
extend the deadline to submit a verified corrected report to 120 days following the request from the Minister and amend the day on which revised compensation is to be provided following the submission of a corrected report to be 45 days after the corrected report is due rather than after it is received;
enable the Minister to determine the quantity of GHGs emitted or establish the emissions limit for a covered facility when no annual report is provided for a compliance period or when the facility emissions limit indicated in the annual report was not calculated in accordance with the Regulations, and any resulting error was equal to or greater than 2%;
enable the Minister to request that a copy of a record required to be kept under subsection 45(1) of the Regulations be provided without delay;
clarify requirements for a unit or a credit to be recognized as a compliance unit, the requirements for their remittance and the information to be provided on their remittance;
clarify the method to calculate complexity weighted barrels for petroleum refineries;
align and correct the regulatory text through miscellaneous administrative changes; and
make consequential amendments to the Environmental Violations Administrative Monetary Penalties Regulations (EVAMPR), as a result of the changes to the Regulations to allow enforcement officers to issue administrative monetary penalties (AMPs) for new requirements under the amendments.

Regulatory development

Consultation

The Regulatory Impact Analysis Statement (RIAS) accompanying the Regulations that were published in July 2019 contains a commitment to review the Regulations in 2022. Building on this commitment, the Department published a scoping paper^{footnote 8} in February 2021 describing the principles and scope of the review of the Regulations. Over 50 responses to the scoping paper were received from provincial and territorial governments, industry, environmental non-governmental organizations (ENGOs), and other stakeholders. The Department reviewed these submissions and used them to inform the content of the Review of the OBPS Regulations: Consultation Paper (the Consultation Paper),^{footnote 9} published in December 2021. The Department received 58 submissions on the Consultation Paper, largely from industry and industry associations. Submissions were also received from provincial and territorial governments, academia and ENGOs. The Department undertook extensive engagement through technical working groups, as well as multi-stakeholder webinars and one-on-one meetings with interested parties. This engagement formed the basis for the proposed Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations (the proposed amendments) that were published in the Canada Gazette, Part I, on October 29, 2022.

The publication of the proposed amendments was followed by a 60-day consultation period ending on December 28, 2022. The Department published a link on the OBPS web page to make the proposed amendments accessible to all concerned parties. The Department also sent an email to provide an overview of the proposed amendments, to disseminate information on the formal consultation process to interested parties, which included regulated facilities, representatives of provincial and territorial governments, industry association and their members and ENGOs.

On November 29, 2022, the Department hosted general consultation sessions (webinars) in English and French to provide an overview of the regulatory proposal and answer questions on the proposed amendments. The most notable subjects discussed were the proposed tightening rates and materiality thresholds. Departmental officials closed the sessions by responding to questions from participants and inviting them to submit their written comments.

Stakeholders were invited to make comments through the Canada Gazette’s new online commenting feature. To support openness and transparency, comments submitted through this tool are now publicly available.

During the 60-day consultation period, the Department received a total of 31 written submissions through the Canada Gazette online tool and by email. Submissions were received from industry and industry associations, provincial and territorial governments, academia and ENGOs. The Department also continued to undertake engagement on the review of the Regulations through technical working groups and one-on-one meetings with interested parties.

The subsequent paragraphs summarize the notable concerns raised by interested parties, as well as the Department’s examination and evaluation of these concerns. Comments that were not addressed in this review of the Regulations may be reconsidered in future reviews. Comments outside of the scope of this review were shared with the appropriate group within the Department or with other government departments for further consideration.

Tightening rates

All but four stakeholders commented on the proposed tightening rates or the overall stringency of the OBPS. Of these submissions, the majority expressed opposition to the implementation of tightening rates. These submissions were largely from industry and industry associations. A number of the comments received on this topic reaffirmed concerns raised during previous consultation periods of the Regulations’ review. Many stakeholders expressed a strong commitment to reduce emissions but reiterated their concerns that tightening rates in combination with the increase to the carbon price would impair the ability of industries to remain globally competitive, in particular in the absence of competitors in other countries being subject to similar costs.

Some submissions indicated that tightening rates were unnecessary to drive decarbonization activities in their sector, while others indicated that tightening rates would have the potential to devalue past and current investments in emission reductions and deter future investments. Several stakeholders mentioned that the proposed tightening rates would outpace the feasible deployment and advancement of technologies and create a circumstance where OBSs exceed best in class performance for their sector. Some stakeholders supported implementing measures, such as border carbon adjustments (BCAs), to protect industry competitiveness, requesting a pause in tightening rates until such measures are in place. Other comments indicated that tightening rates may not be necessary to ensure emission reductions and a robust OBPS credit market, recommending a delay in tightening rate implementation until market performance could be more fully assessed.

Some sectors requested no or reduced tightening rates on certain processes or products. The steel sector noted that proposed tightening rates do not take into account the high proportion of fixed industrial process emissions at facilities in this sector, along with the technology constraints that prevent reducing this portion of GHG emissions. The fertilizer sector noted that carbon dioxide (CO₂) stored in urea cannot be reduced and therefore these emissions should not be subject to a tightening rate. Some sectors requested that tightening rates not be applied to products that are considered essential to decarbonizing the economy.

On the other hand, several submissions from ENGOs supported the introduction of tightening rates. One submission indicated that tightening rates were necessary to ensure standards keep pace with Canada’s and industries’ commitments to achieve net-zero emissions by 2050. Another submission argued that the proposed tightening rates are too low, indicating they should be increased to 4% annually. Some industry submissions also recognized the need for, or at least did not oppose the introduction of tightening rates. These submissions recognized their role in maintaining credit markets but tended to caveat this support with requests for uniformity in rates across provinces and territories and among sectors, regular reviews, and supplemental funding.

Requests for additional support from the Government to help mitigate cost increases as a result of tightening rates were common. Specific suggestions included the return of proceeds collected from compliance to the specific facility that paid it, and tax incentives that align with what other jurisdictions have in place. A number of stakeholders stressed the importance of regular reviews of tightening rates and commented on the tightening rates applying past 2030. Some indicated that the tightening rates should not go beyond 2030, with one stakeholder citing as a rationale that carbon leakage and competitiveness concerns had not been assessed beyond this time frame.

Increasing the stringency of OBSs over time has been part of the design of the OBPS since its inception, in line with the PCF and the Pan-Canadian Approach. The tightening rates are intended to balance the objectives of ensuring the marginal price signal is maintained with mitigating the risks of carbon leakage and adverse competitiveness impacts for at risk sectors. Delaying the application of tightening rates could create risks of having too many credits in the market for compliance purposes, which would drive down the price of surplus credits and weaken the price signal, and the incentive to reduce emissions. Extending the tightening rate past 2030 increases certainty related to the future stringency of the OBPS and is in alignment with Canada’s long-term decarbonization objectives. In addition, the Department is of the view that the tightening rate should apply to all products and processes to ensure the marginal price signal is maintained across products and emission types.

The Government of Canada is supporting the deployment of low-carbon technology through programs like the Net Zero Accelerator Initiative, the Strategic Innovation Fund, and the Low Carbon Economy Fund. Budget 2023 announced additional funding for low-carbon technology through the Clean Technology Investment Tax Credit, the enhanced Investment Tax Credit for Carbon Capture, Utilization, and Storage and the Canada Growth Fund. These programs will support the decarbonization of many of the sectors found to be at risk of competitiveness impacts and carbon leakage resulting from carbon pricing by encouraging investment and reducing compliance costs. In jurisdictions where the OBPS proceeds are returned directly through federal programming, they support low-carbon technology at OBPS facilities and clean electricity projects and further the decarbonization of Canada’s industrial sectors. Combined with carbon pricing, these policies will help industry adopt clean technology and catalyze the large-scale investments required to achieve Canada’s net-zero goals.

With respect to concerns raised surrounding carbon leakage between jurisdictions within Canada, as a result of variations in stringency across regional carbon pricing systems, the August 2021 update to the federal benchmark^{footnote 3} aimed to reduce these differences by requiring alignment of the marginal price signal across output-based pricing systems in Canada. However, carbon leakage within the country could occur to the extent that standards, free allocations, or revenue recycling approaches differ between carbon pricing systems, therefore leading to unequal average costs.

In response to the Commissioner of the Environment and Sustainable Development’s Independent Auditor’s Report on Carbon Pricing,^{footnote 10} the Department committed to begin federal-provincial-territorial work on the interim review of the federal benchmark in 2023. This work has commenced and the results of this work will be considered in the next review of the Regulations.

Risk assessments for carbon leakage and adverse competitiveness impacts

Industry, industry association, and one academic commented on the methods used to evaluate carbon leakage risks and adverse competitiveness impacts. Some industry advocated for risk assessments that included considerations regarding differences in carbon costs between Canada and other regions in which competitors are located, as well as risks of both production and investment leakage, caused by direct and indirect carbon costs. The Department also received some requests to take sector- and region-specific considerations into account for the risk assessments, as well as the cumulative impacts of climate policies on industrial sectors.

Four industrial stakeholders expressed concern about the level of sectoral aggregation in the Department’s EC-Pro model affecting results for certain subsectors, the lack of transparency and accuracy related to the assumptions in the model, and the fact that dynamic modelling does not capture important technological nuances, which may have caused the risk of carbon leakage associated with their sector to be underestimated. Certain stakeholders from the fertilizer and iron and steel also requested that inputs into the EC-Pro model be refined to better reflect sectoral realities, such as those regarding the marginal abatement cost of capturing, transporting and long-term storage of carbon emissions, the timelines for project execution, and the expected emissions reductions over time.

Concerns were also expressed about what was seen as arbitrary components of the EITE analysis, such as the use of projections to assess EITE risk categories and the risk categories themselves or misalignment with other jurisdictions’ methodology to assess risks. Stakeholders expressed concern regarding EITE assessment results for sectors whose risk levels were lower in the tightening rate analysis than in previous risk assessments for the emission reduction factors. Some stakeholders also asserted that the thresholds of emissions intensity (EI) and trade exposure (TE) that triggered reduced tightening rates were too restrictive because they did not consider the full risks from very high levels of trade exposure. One stakeholder expressed that the EC-Pro model is a fundamental tool to get right given its importance in assessing EITE risk status, future incentives to support decarbonization and its role in assessing whether provincial programs meet the federal benchmark. Other stakeholders indicated that the proposed approach is too generous, advocating for greater stringency to be applied to all but the most at-risk sectors.

The Department’s current approach to assessing carbon leakage and adverse competitiveness impacts is similar to approaches applied across carbon pricing systems, such as Alberta’s Technology Innovation and Emissions Reduction Regulation, the European Union Emission Trading System, and California’s Cap-and-Trade Program. The Department aims to assess risks at the national level consistent with the aim of ensuring the federal OBPS is national in scope and can apply in any province or territory, as required. The use of EITE metrics prioritizes consistent and transparent methods for assessing risks of carbon leakage and adverse competitiveness impacts to ensure all sectors are evaluated in a comparable manner.

To address stakeholder concerns raised with the Phase 2 analysis, and in line with the Department’s intention to review the post-2026 tightening rates as part of the next review of the OBPS, the Department has removed the Phase 2 analysis from the assessment of risk levels for the Canada Gazette, Part II. This approach allows for sector risks to be assessed at a higher resolution, and using historic data that does not assume emissions reductions are achieved in particular sectors. In addition, two new EITE thresholds have been introduced to better reflect the risk for sectors at varying levels of EI and TE. Under the revised approach, sectors are considered to be at very high EITE risk if EI is at least 10% and TE is at least 20%; or EI is at least 6% and TE is at least 40%; or EI is at least 3% and TE is at least 80%.

Industrial process emissions

Four submissions from industry and industry associations suggested modifications to the Department’s approach on industrial process emissions, which are emissions from an industrial process that involves a chemical or physical reaction other than combustion and the purpose of which is not to produce useful heat. They included concerns about the absence of feasible alternatives and commercially available technologies to reduce process emissions without reducing production. While some recognized coverage of industrial process emissions would incentivize companies to reduce these GHGs emissions over time, some stakeholders suggested removing, reducing, or delaying the inclusion of industrial process emissions in the Regulations to allow time for research and development of new technology, or implementation of carbon capture and storage projects or direct air capture. The fertilizer sector has requested that industrial process emissions that are captured in urea be exempted from coverage under the OBPS.

The amendments do not change the approach to industrial process emissions. The updated federal benchmark requires that output-based pricing systems cover these emissions; therefore, exempting industrial process emissions from the federal OBPS would be inconsistent with the stringency requirements imposed on provincial and territorial systems through the Pan-Canadian Approach. Industrial process emissions were always considered in the determination of the emissions reduction factors for OBSs. The Department is not currently reviewing the emissions reduction factors for existing standards. To ensure alignment between new and existing OBSs, the Department used the same approach to set the emissions reduction factors for the development of new OBSs. This approach reflects the challenges associated with reducing industrial process emissions but continues to incentivize reductions from all GHG emissions sources over time.

Compliance flexibility and emissions trading markets

There were eleven submissions that provided feedback on compliance flexibility. Of these, six industry and ENGOs expressed support for linking carbon pricing systems across Canada. There were three comments among these submissions from industry discussing limits on surplus credits. One industry association requested that the mandatory minimum of 25% of compensation made through excess emissions charge payments be eliminated, while one oil and gas stakeholder and one ENGO requested that it be retained as it is.

Submissions on compliance flexibility also ranged from enabling the transfer of surplus credits when transitioning from the federal OBPS to a provincial carbon pricing system for industry, removing the expiration of compliance units and accepting credits for compliance that are generated outside Canada and North America, provided verifiable offset protocols are in place. On the other hand, some comments advised against increasing compliance flexibility provisions noting their importance in maintaining the marginal price signal on some emissions, as in their view, the 2% and 1% tightening rates are insufficient to provide the necessary market signals to ensure industrial sectors invest in decarbonization at the pace necessary to achieve Canada’s climate targets. Although not contemplated in the amendments, there were also comments that opposed placing limits on the use of offset credits by OBPS participants.

Rules related to compliance flexibility remain unchanged. Limitations on the use of compliance units, including when the scope of a system changes, and expiry of credits are common design features in other emissions trading systems. Such limitations are essential to maintain the marginal price signal by preventing a flood of credits in the market. This general principle has been taken into account in establishing the updated federal benchmark criteria.

No new limits on the use of offset credits are being introduced as part of these amendments. There is a robust process under the Regulations to recognize offset credits generated under provincial offset programs when certain criteria are met. The Government of Canada has not yet taken decisions with respect to acquiring, selling, or otherwise authorizing the use of international offset credits under Article 6 of the Paris Agreement in the Canadian context, and, as such, the use of internationally transferred mitigation outcomes (ITMOs) towards compensation obligations under the OBPS is not being contemplated at this time.

New output-based standards

The Department established 10 working groups and held over 30 meetings in support of the development of new OBSs, including undertaking extensive data-gathering exercises. In general, stakeholders were supportive of the development of new OBSs and appreciative of the Department’s collaborative approach. Many of the concerns raised through the working groups were addressed in the design of the standards. For example, stakeholders were concerned that where new OBSs were being developed to apply to activities engaged in at covered facilities to which an existing OBS applied, the reference years should remain consistent with the existing OBSs (2014–2016). As a result, the standards for the surface mining of oil sands and extraction of bitumen, and the production of ethylene glycol with six or fewer monomer units, were set using 2014–2016 data for consistency with the method used to set existing OBSs.

In general, industry stakeholders engaged in these activities expressed support for the development of additional OBSs for activities. These standards are being added to ensure the OBPS is national in scope and can apply anywhere in Canada if required. Specifically, submissions from the oil sands industry have noted support for the oil sands mining standard and the inclusion of fugitive methane emissions from area sources within that standard. Stakeholders expressed support for the inclusion of these emissions under the OBPS instead of under the proposed methane regulations. Under Canada’s methane regulations, area sources of methane have been excluded due to limited technological opportunities for mitigation. Pricing these emissions may incentivize innovative technology solutions to reduce these emissions.

Some affected stakeholders expressed concern related to the competitiveness and carbon leakage assessments completed for the new output-based standards. As a result of new data submitted between prepublication and final publication of the amendments, the standard for the production of calcined petroleum coke for use in aluminum production from alumina was adjusted as part of the Phase 3 assessment for that activity.

Review of existing output-based standards

Working groups were established to consider changes to the urea liquor standard, and to the iron and steel standards. Meetings were also held to consider changes to the automotive standard. Stakeholders were generally supportive of the review of the urea liquor standard and the inclusion of a new separate granular urea activity. The automotive sector was generally supportive of the change to the automotive standard. However, it noted that facilities producing both electric vehicles and internal combustion vehicles should be eligible for a single standard for both activities due to the challenges of allocating emissions to separate activities occurring at the same facility. Under the OBPS Regulations, all covered facilities that are engaged in an industrial activity listed in Schedule 1 to the Regulations must use the prescribed standard for that activity and the production of internal combustion vehicles is listed on Schedule 1. This ensures all covered facilities producing the same products are treated the same under the Regulations. As there is no numeric OBS for electric vehicle production, facilities engaged in this activity would need to use a calculated OBS. Facilities that need to calculate their OBSs and that are engaged in more than one activity at their facility will need to allocate emissions between activities in a manner that is rigorous, objective and based on sound engineering principles; however, the method to be used to allocate emissions is not prescribed.

Considerable work was completed on the review of the iron and steel standards. The working group held 11 working group meetings and collected a substantial amount of data to support the revisions. Due to the complexity of the iron and steel sector, the Department requires more time to further understand the products developed at different types of steel mills in Canada, how standards can be developed that appropriately capture the distinct products made at various facilities and provide incentives for facilities to reduce the emissions associated with producing these products and to continue its engagement with the iron and steel sector. For these reasons, the amendments do not include any changes to the existing iron and steel standards. Proposals will continue to be considered and, if appropriate, changes to the standards would be proposed as a part of a future review of the Regulations.

The Department received one comment on the rule preventing facilities that produce gold but also produce silver, platinum, or palladium, from including the OBS for the production of silver, platinum and palladium in their emissions limit. Similarly, facilities that produce both base metal ore concentrate and gold, silver, platinum or palladium, are only allowed to include the standard for base metal ore concentrate in their emissions limit. The stakeholder’s view was that facilities should be able to access all numeric standards related to the production of each of the various products at their facilities. When these standards were developed, emissions associated with silver, platinum or palladium production at gold mines were included in the emissions when calculating the gold OBS. Similarly, emissions associated with gold, silver, platinum or palladium production at base metal ore concentrate mines were included in this standard during its development. In order to ensure facilities would not be over-allocated, these exceptions were put in place. These standards may be revisited in the next review of the Regulations.

The Department received seven submissions on the treatment of electricity. An ENGO argued that the electricity sector should not be under the OBPS and should be fully exposed to the fuel charge, arguing that it is not an emissions-intensive or trade-exposed sector, and that decarbonizing the sector is a keystone requirement to support emissions reductions across the economy. Other submissions from industry and an industry association raised concerns related to the interactions between the Regulations and the proposed Clean Electricity Regulations (CER), including that differing dates for the recognition of new facilities under the two regulations could create incentives for the construction of new gas fired generation in the short term. Finally, one government expressed concern that the declining output-based standard that applies to new electricity generation may dissuade the use of natural gas as an interim solution, especially in the North, as they continue to shift from diesel.

The treatment of electricity generation in the OBPS has not been considered in this review. The Department will consider the treatment of electricity generation under the OBPS as part of the review of carbon pricing in Canada by 2026. At that time, the Department will take into account other related initiatives, including the CER. Comments strictly related to the proposed CER were shared with the appropriate group within the Department.

The amendments introduce a provision that exempts electricity generation facilities that generate electricity from liquid or gaseous fuels for distribution to remote communities from becoming mandatory facilities under the Regulations. This exemption aligns the OBPS provisions with exemptions from the fuel charge for remote electricity generation facilities and may ease some concerns related to electricity generation in Northern regions.

Reducing administrative burden

Industry stakeholders provided some feedback on the reduction of the administrative burden. Specifically, six submissions supported the harmonization of GHG emissions quantification methodologies. These specifically expressed an interest in greater consistency between the Regulations and the GHGRP. However, some stakeholders expressed concerns on the availability of the quantification methods. They would appreciate the updates to be released well in advance to allow industries sufficient time to make changes. One submission also requested greater consistency between climate policies and regulations, while another one suggested streamlining reporting among reporting programs, including provincial reporting, to reduce duplication.

The Department is working on harmonizing the GHG quantification methods to the extent possible by making it easier for the Minister to update those in the federal OBPS to align better with other GHG emissions quantification methods as they evolve over time. This is the first step towards greater harmonization of quantification methods.

To the extent possible, the Department will, starting with the 2024 compliance period, harmonize with quantification methods required by the GHGRP for the same year. Differences in quantification methods may have to remain to account for differences in the scope and objectives of the OBPS and the GHGRP. The Department intends to explore opportunities to further increase the level of harmonization between the two programs over time. The interest in better integration will also be considered as updates to the electronic reporting systems of the OBPS and the GHGRP are being planned.

Accurate reporting

Material discrepancy

The Department received five submissions from industry expressing opposition to an increase in the stringency in the material discrepancy threshold for production. Stakeholders expressed that lowering the material discrepancy threshold for production to 0.1% is too low and unnecessary and that it will increase complexity in reporting and verification. Several stakeholders misunderstood the proposal and were concerned that the 0.1% represented a calibration requirement. Some stakeholders recommended that the threshold for production be consistent with the GHG emissions materiality threshold of 5%, while others suggested that the materiality threshold for production should only trigger a refiling and re-verification if the total cost impact were $20,000 or greater. One stakeholder noticed that the 0.1% threshold was inherently flawed as production value must be rounded to three significant figures.

It is important to note that a material discrepancy occurs when, in consideration of the reporting requirements prescribed under the Regulations, there is an error or omission in the quantity of GHG emissions or production reported. The Regulations contain requirements to ensure that measuring devices used to measure production are installed, operated, maintained and calibrated in accordance with the manufacturer’s specifications or, if those specifications are not available, any applicable generally recognized national or international industry standard and maintain accuracy within plus or minus 5%. Values provided by measuring devices that are compliant with regulatory requirements would normally be considered compliant.

The Department has decided to not continue with the proposed material discrepancy threshold for production of 0.1% at this time given the challenges that the threshold represents for some facilities. However, the Department is still of the view that errors below the 5% threshold can represent very significant CO₂e tonnage in some cases. The verification body is required to identify all errors in an annual report whether they are material or not. The amendments now add an obligation on the person responsible to correct all errors identified by the verification body prior to the submission of the annual report, if possible. The Minister retains discretion to request corrections of any errors whether above or below the materiality threshold. The Department will reassess the materiality threshold for production in the next review.

Approach for corrected reports

Some submissions were received from industry regarding adjustments to the submission of corrected reports, including support for removing the requirement to submit a corrected report automatically once an error is identified. One stakeholder expressed that the requirements to correct or update the quantification of emissions or production values should be left to the discretion of the person responsible. Finally, one industry association requested further clarification on what constitutes an error.

Annual reports must be submitted in accordance with the requirements of the Act and the Regulations. Section 176 of the Act requires the person responsible for a covered facility to notify the Minister of any error or omission within five years of the submission of the annual report. The Regulations now only require the submission of a corrected report accompanied by a verification report where the person responsible for a covered facility notifies of an error or omission that would have constituted a material discrepancy if it had been found during the verification of the annual report. It should be noted that the Minister maintains the authority under section 177 of the Act to request a corrected report should they deem it necessary.

Measuring devices

The Department received comments on the calibration requirements for measuring devices used in GHG quantification. One industrial stakeholder indicated that the percentage specified in the proposed calibration requirements was inconsistent with the requirements of certain sampling methods, including for continuous emission monitoring systems (CEMS). The Department agreed that the proposed requirement could contradict the requirements regarding measuring devices set out in the Quantification Methods in some cases. The amendments were updated to require that measuring devices used in the quantification of GHGs meet the requirements of the Regulations, unless the Quantification Methods already contains installation, operation, maintenance, calibration and accuracy requirements.

Voluntary participation

One comment from an ENGO expressed support for streamlining the process for voluntary participation in the OBPS, indicating that this could broaden the market and lead to more efficient mitigation pathways for all participants. Another industry association provided comments on the GHG threshold for participation in the OBPS. Several comments were also received in response to the drafts of the Revised Policy regarding voluntary participation in the Output-Based Pricing System, the Policy for recognizing additional industrial activities from sectors at significant risk of carbon leakage and competitiveness impacts and the List of recognized additional industrial activities under the Output-Based Pricing System, that were posted on the Department’s OBPS web page for comment. These comments will be considered as these policies are finalized, prior to January 1, 2024.

Policy certainty and coherence

Stakeholders from industry, their association and an ENGO were concerned about the lack of regulatory and policy certainty in Canada’s decarbonization efforts, particularly regarding the carbon pricing schedule beyond 2030. They urged the Government to provide clear timelines for review and propose tightening pathways well in advance of the stringency adjustment to enable industry to prepare for compliance requirements and reduce the risk of stranding assets and carbon leakage. Stakeholders suggested implementing measures to increase policy certainty, such as accelerating the development and implementation of the “Carbon Contracts for Difference” investment offering. However, some stakeholders from various sectors expressed concerns about the continual regulatory changes, which create uncertainty and unpredictability, especially for EITE industries. They suggested freezing existing regulations and incentivizing GHG reducing investments to ensure producers have the assurance required to make long-term business decisions.

The Government of Canada recognizes that regulatory and policy certainty is a key driver for investment in decarbonization. In the 2030 Emissions Reduction Plan, the Government committed to exploring measures to enhance carbon price certainty. Updates to the federal benchmark published in 2021 set the carbon price trajectory out to 2030 and require carbon markets to maintain a strong price signal in line with the minimum national carbon pollution price across all covered emissions. To provide additional certainty and allow carbon pricing systems to function effectively, the benchmark also states that where the federal backstop applies in 2023, it will remain in place until at least the end of 2026. In addition, the Government is reinforcing the investment signals created by Canada’s carbon pricing systems with other tools, such as investment tax credits for carbon capture, utilization and storage, clean hydrogen, clean electricity, clean manufacturing, clean technology and financial instruments through the Canada Growth Fund.

Modern treaty obligations and Indigenous engagement and consultation

An assessment examined the geographical scope and subject matter of the amendments in relation to modern treaties in effect, and did not identify, at this time, potential modern treaty implications.

In addition, the amendments respect the Government of Canada’s obligations in relation to rights protected by section 35 of the Constitution Act, 1982 and modern treaties, and international human rights obligations. The Government of Canada continues to work with Indigenous organizations on the federal approaches to the pricing of carbon pollution and the return of proceeds so they consider the unique circumstances and priorities of Indigenous peoples.

Instrument choice

The Department considers the amendments to be necessary to continue to improve the Regulations and maintain the integrity of the OBPS. Given the new policies and investments committed to in the ERP, and as more technology becomes available, there is a risk that the incentive to reduce GHG emissions in the OBPS could diminish considerably if increased stringency through the introduction of tightening rates is not implemented. As the excess emissions charge increases to $170 per tonne of CO₂e by 2030, there is a concern that there will be a surplus of credits in the market resulting in a flood of surplus credits priced lower than the excess emissions charge, lowering the incentive for sectors under the OBPS to reduce their GHG emissions in the absence of these amendments. Furthermore, the amendments align the stringency of the federal OBPS with the requirements of the federal benchmark.

Finally, the clarifications to various provisions of the regulatory text, by means of the amendments, facilitate the Department’s administration of the Regulations and help ensure that the Regulations are consistent with the Department’s policy intent.

Regulatory analysis

Carbon leakage and adverse competitiveness impact risk assessment

In order for the OBPS to continue to mitigate the risks of carbon leakage and adverse competitiveness impacts, the EITE analysis, outlined in the “Background” section above, has been updated to reflect the increased excess emissions charge set out in Schedule 4 to the Act, and the tightening rates. The results of this analysis were used to identify sectors at very high EITE risk. These sectors were assigned a lower tightening rate of 1% per year for 2023 onwards in lieu of the 2% tightening rate applied to standards for all other sectors, except electricity generation. Applying a tightening rate to these sectors incentivizes efforts to reduce these emissions over the longer term.

The tightening rates are set to maintain sufficient demand for credits in the OBPS to preserve the marginal price, taking into account expected reductions in emissions in response to the carbon price and other supporting measures. The updated benchmark states that output-based pricing systems for industry must be designed to maintain a marginal price signal equivalent to the minimum national carbon pollution price across all covered emissions. The tightening rates play an important role in aligning the OBPS with the updated federal benchmark. The impact on the marginal price signal is assessed both at the national level (i.e. by assuming the federal OBPS is applied across Canada) and based on the current scope of application of the OBPS. The assessment of the impact on the marginal price signal was undertaken using an approach that was consistent with that used to assess provincial and territorial systems against the benchmark.

The Department applied a Phase 1 analysis to evaluate the EITE risk levels of sectors that are covered under the OBPS. This is required to understand the extent to which the price trajectory, in combination with the tightening rate, could increase the risk of carbon leakage and competitiveness impacts on these sectors. The Phase 1 analysis was conducted at a stringency consistent with 2026 (i.e. with a tightening rate of 2% per year applied from 2023 to 2026 and a carbon price of $110 per tonne of CO₂e),^{footnote 11} which is the minimum national carbon price in 2026. The use of historical data for this type of analysis is limited by the fact that it does not take into account uncertainties regarding the costs of deploying emissions reduction technologies and changes to economic trends that will occur in the future. Therefore, a 2026 stringency level was used for the static analysis instead of a 2030 stringency level to capture an increase in the stringency while mitigating the many uncertainties of technologies and economic trends associated with using historic data to assess impacts into the future.

Table 2 shows the results of the Phase 1 analysis. Sectors are shown to be at low,^{footnote 12} medium,^{footnote 13} high^{footnote 14} or very high risk.^{footnote 15} Specifically, the Phase 1 analysis identifies the cement, lime, petrochemicals, aluminum, iron and steel and some organic basic chemicals standards as being from sectors at very high risk of carbon leakage and competitiveness impacts. As a result, the annual tightening rate applied to activities undertaken in these sectors, as outlined in Table 2, is set at 1% from 2023 onwards, to mitigate increased competitiveness impacts and carbon leakage risks. The annual tightening rate for all other sectors is set at 2% from 2023 onwards, except for electricity generation for which no tightening rate is applied.

The broad approach to electricity generation in the federal OBPS will be reviewed as part of future reviews, taking into account the other related initiatives and clean electricity goals, including the CER.

Table 2: Phase 1 EITE analysis results at 2026 stringency
NAICS code	NAICS sector name	Activities as identified in Schedule 1 to the Regulations	2017 to 2019 average emissions intensity (EI)^{table d1 note a}	2017 to 2019 average trade exposure (TE)^{table d1 note b}	EITE risk category (direct costs)
32731	Cement manufacturing	Item 7	11%	39%	Very high
32741	Lime manufacturing	Item 8	9.6%	30%	Very high
32511	Petrochemical manufacturing	Sub-items 17(a) to (f)	8.8%	42%	Very high
33111	Iron and steel mills and ferro-alloy manufacturing	Items 19 and 20	6.6%	48%	Very High
33131	Alumina and aluminum production and processing	Items 40, 41 and 43	2.8%	84%	Very High
32519	Other basic organic chemical manufacturing	Items 13 and 34 and sub-items 3(c) and 17(g)	2.6%	87%	Very High
32512	Industrial gas manufacturing	Item 6	6.7%	21%	High
211110	Oil and gas extraction (except oil sands)	Sub-item 1(a) and item 4	5.1%	67%	High
3253	Pesticide, fertilizer and other agricultural chemical manufacturing	Sub-item 29(c), (d), and (e)	5.0%	51%	High
21114	Oil sands extraction	Items 2, 3.1 and sub-item 1(b)	5.0%	79%	High
4862	Pipeline transportation of natural gas	Item 5	3.9%	57%	High
3253	Pesticide, fertilizer and other agricultural chemical manufacturing	Sub-items 29(a) and (b)	3.6%	51%	High
3221	Pulp, paper and paperboard mills	Item 36	3.3%	75%	High
33141	Non-ferrous metal (except aluminum) smelting and refining	Sub-items 23(c), (e), and (f)	2.4%	73%	Medium
32411	Petroleum refineries	Sub-item 3(a)	2.2%	46%	Medium
21221	Iron ore mining	Sub-items 21(b) and 26(a)	1.7%	90%	Medium
32519	Other basic organic chemical manufacturing	Item 15	1.7%	87%	Medium
32419	Other petroleum and coal product manufacturing	Sub-item 3(b)	1.6%	46%	Medium
33141	Non-ferrous metal (except aluminum) smelting and refining	Sub-items 23(a), (b), and (d)	1.5%	73%	Medium
2121	Coal mining	Items 25, 27 and 28	1.5%	88%	Medium
212392	Diamond mining	Sub-item 26(e)	1.2%	98%	Medium
32419	Other petroleum and coal product manufacturing	Item 42	1.2%	46%	Medium
31122	Starch and vegetable fat and oil manufacturing	Items 31 and 33	1.1%	66%	Medium
212396	Potash mining	Item 24	1.1%	88%	Medium
21221	Iron ore mining	Sub-item 21(a)	1.1%	90%	Medium
32742	Gypsum product manufacturing	Item 10	1.0%	19%	Medium
2123	Non-metallic mineral mining and quarrying	Item 24.1	1.0%	66%	Medium
32721	Glass and glass product manufacturing	Item 9	0.82%	69%	Low
3113	Sugar and confectionery product manufacturing	Item 35	0.76%	71%	Low
31213, 31214	Wineries and distilleries	Item 32	0.67%	73%	Low
3114	Fruit and vegetable preserving and specialty food manufacturing	Item 30	0.58%	59%	Low
21222	Gold and silver ore mining	Sub-items 26(c) and (f)	0.57%	39%	Low
311A0 (3112, 3118, 3119)	Miscellaneous food manufacturing	Item 35.1	0.55%	50%	Low
32513, 32518, 3252, 3255, 3256, 3259	Other chemicals	Item 16	0.49%	82%	Low
21229	Other metal ore mining	Sub-item 26(b)	0.42%	53%	Low
21223	Copper, nickel, lead and zinc ore mining	Sub-item 26(d)	0.38%	54%	Low
321	Wood product manufacturing	Item 39	0.36%	55%	Low
3262	Rubber product manufacturing	Item 44	0.36%	82%	Low
32732, 32733, 32739, 3271, 3279	Other non-metallic mineral product manufacturing	Item 11	0.33%	32%	Low
32513, 32518, 3252, 3255, 3256, 3259	Other chemicals	Item 14	0.32%	82%	Low
32732, 32733, 32739, 3271, 3279	Other non-metallic mineral product manufacturing	Item 12	0.21%	32%	Low
3361	Motor vehicle manufacturing	Item 37	0.15%	91%	Low
32541	Pharmaceutical and medicine manufacturing	Item 18	0.13%	89%	Low
33121	Iron and steel pipes and tubes manufacturing from purchased steel	Item 22	0.10%	50%	Low
Table d1 note(s) Table d1 note a EI is the ratio of direct carbon cost to gross value added for the sector. Return to table d1 note a referrer Table d1 note b TE is equal to (Imports + Exports) ÷ (Imports + Sales) for the sector. Return to table d1 note b referrer

Adding new output-based standards

The three-phased approach previously described was applied to determine whether any phase of the analysis indicates a high level of risk of carbon leakage and adverse competitiveness impacts or provides a basis for an OBS to be considered for an upwards adjustment from 80% to 90% or 95%. An assessment was also completed to determine whether industrial process emissions make up a significant portion of the total emissions for facilities undertaking the activity. Activities found to have a proportion of industrial process emissions of 30% or more were considered for adjustment from 80% to 90%, and those for which standards were adjusted to 90%, based on the Phase 1, 2 and 3 analyses, were considered for adjustment from 90% to 95%.

Based on the results of the Phase 1 and 2 analyses, all sectors were found to be in the medium or low EITE risk category and therefore emissions reduction factors were not adjusted for any of the new standards on this basis. Based on Phase 3 of the analysis, the stringency of the OBS for the production of calcined petroleum coke for use in aluminum production from alumina was adjusted due to the finding that of an elevated risk of carbon leakage and competitiveness impacts. Four activities were found to have a proportion of industrial process emissions of 30% or more. The emissions reduction factor for three of these activities were adjusted to 90%, with the emissions reduction factor for the production of calcined petroleum coke for use in aluminum production from alumina being further adjusted to 95%. Table 3 below lists the new activities, the results of the competitiveness and carbon leakage assessments and the emissions reduction factor assigned to each activity.

Table 3: Emissions reduction factors
Sector	Activity	Phase 1 EITE risk level	Phase 2 EITE risk level	Phase 3 outcome	Industrial process emissions ≥ 30%	Emissions reduction factor
Oil and gas production	Surface mining of oil sands and extraction of bitumen	Medium	Low	No basis for adjustment	No	80%
Chemicals	Production of ethylene glycol with six or fewer monomer units	Medium	Low	No basis for adjustment	Yes	90%
Mining and ore processing	Production of evaporated salt through solution mining	Low	Low	No basis for adjustment	No	80%
Food processing	Production of malt	Low	Low	No basis for adjustment	No	80%
Wood products	Production of wood veneer or plywood	Low	Low	No basis for adjustment	No	80%
	Production of lumber	Low	Low	No basis for adjustment	No	80%
	Production of particle board and low, medium or high-density composite panels, including hardboard	Low	Low	No basis for adjustment	No	80%
Aluminum	Aluminum production from alumina	Medium	Low	No basis for adjustment	Yes	90%
	Production of baked anodes for use in aluminum production from alumina	Medium	Low	No basis for adjustment	Yes	90%
	Production of calcined petroleum coke for use in aluminum production from alumina	Medium	Low	Adjusted	Yes	95%
	Production of alumina from bauxite	Medium	Low	No basis for adjustment	No	80%
Rubber products	Production of pneumatic tires	Low	Low	No basis for adjustment	No	80%

Updating existing output-based standards

As a result of updates to GWPs in Schedule 3 to the Act, the amendments update existing OBSs when the change in GWP values results in a material change of more than plus or minus 1% in the value of the OBS. Table 4 below includes the activities that meet this threshold and the percent change in those standards. In addition to the standards listed below, the production by mining coal deposits of metallurgical coal (sub-item 25(b) of Schedule 1 to the Regulations) has seen a material change in emissions associated with the changing GWPs; however, the calculation of the original standard included an error that resulted in no need to update this standard.

Table 4: Existing activities for which there is at least a 1% change in OBS value as a result of the updated GWPs
Activity	Percentage change in OBS value
Industrial processing of potatoes for human or animal consumption, item 30 of Schedule 1 to the Regulations	2.4%
Production of nitric acid by the catalytic oxidation of ammonia, sub-item 29(a) of Schedule 1 to the Regulations	−6.3%

Benefits and costs

The benefits and costs discussed below are attributable to the set of amendments, including the amendments resulting from the review of the Regulations and the Order Amending Schedule 4 to the Greenhouse Gas Pricing Pollution Act.^{footnote 16} This includes an increasing excess emissions charge up to $170 per tonne of CO₂e in 2030, the introduction of tightening rates on OBSs, and new and updated OBSs. The policies included in the set of amendments are integral to one another and modelling them together ensures a complete and accurate representation of the expected impacts, reflective of both the intended and expected outcomes of the interdependent policies.

Summary

The regulatory analysis compares a “Regulatory Scenario” (set of amendments) to a “Baseline Scenario” where there is no increase to the excess emissions charge (Schedule 4 to the Act) or increased stringency of OBSs. The analysis assesses the benefits of the decreased emissions from the set of amendments and expected losses to Canadian society from decreased economic activity. Decreases in sectoral production due to increased costs result in decreases in overall economic welfare of households. However, there are also fewer GHG emissions in the Regulatory Scenario, causing an increase in global societal benefits due to avoided climate change damages when compared to the Baseline Scenario.

The Baseline Scenario and the Regulatory Scenario were modelled using EC-Pro, the Department’s peer-reviewed, multi-region, multi-sector, provincial-territorial computable general equilibrium (CGE) model. EC-Pro assesses a number of variables, including GHG emissions and household economic welfare. EC-Pro simulates the Canadian economy and calculates the impacts of the set of amendments by calculating the new set of prices and variables that will return the economy to equilibrium. The incremental impacts of the set of amendments can be estimated by comparing the results from the Baseline Scenario to those from the Regulatory Scenario. The analysis then applies the social cost of GHGs^{footnote 17} to monetize the benefits of reduced domestic GHG emissions, which was conducted outside of the CGE model. The monetized administrative and verification costs of the set of amendments were also estimated separately, outside of the CGE model.

The analysis of the set of amendments was conducted based on the scope of application at the time of the publication of the amendments, with the federal OBPS currently applying in 2023 in Manitoba, Prince Edward Island, Yukon, and Nunavut. While measured impacts are limited to participating jurisdictions, the amendments include provisions that will help ensure the OBPS is national in scope and can apply anywhere in Canada if required.

As the set of amendments provide covered facilities with financial incentives for continuous emissions reductions, the Regulatory Scenario will result in more emissions reductions than are expected in the Baseline Scenario. The cumulative incremental domestic GHG emissions reductions are estimated to be between 2.5 and 4.2 Mt of CO₂e, with a central estimate of 3.3 Mt of CO₂e over the 2023 to 2032 period. Using the updated social cost of greenhouse gas (SC-GHG) emissions estimates, published in 2023, which start at a value of $279 per tonne of carbon dioxide CO₂ (2022 Canadian dollars) in 2023 and increase over time, the set of amendments could result in societal benefits of $680 million to $1,140 million, with a central estimate of $910 million. By 2032, compared to the Baseline Scenario, the set of amendments is estimated to result in a decrease in Canadian household welfare of $400 million to $670 million, with a central estimate of $535 million. This is an estimate of the value that households, assumed to be the owners of the factors of production, labour and capital, through decreases in the wages earned by workers and the profits earned by firms (facilities), forego from decreased consumption. The incremental proceeds from the federal OBPS compensation obligations that would be redistributed to backstop jurisdictions could offset costs by $175 million to $350 million, with a central estimate of $265 million over the ten-year period. Therefore, the total costs associated with the set of amendments could lower Canadian household welfare by $225 million to $315 million, with a central estimate of $270 million. Based upon all monetized benefits and costs, there is an estimated net benefit ranging from $460 million to $825 million, with a central estimate of $640 million.

Analytical framework

The impacts of the amendments have been assessed in accordance with the Canadian Cost-Benefit Analysis Guide: Regulatory Proposals.^{footnote 18} Regulatory impacts have been identified, quantified, and monetized, where possible, and compared incrementally to a Baseline Scenario.

Key impacts: The logic model in Figure 1 illustrates the incremental impacts of the amendments that the Department is able to quantify and monetize in this analysis. Compliance actions under the amendments are expected to result in incremental reductions in domestic GHG emissions, increased capital, and operating costs for industry, as well as administrative costs for both industry and Government. Distributional impacts, such as sector-specific and region-specific results, are analyzed separately.

Time frame of analysis: A key objective of the amendments is to have the OBPS remain aligned with the federal benchmark. The updated benchmark applies for the 2023–2030 period. The quantitative assessments applied under this RIAS and to benchmark assessments are based on Canada’s 2022 Reference Case projections.^{footnote 19} For consistency with the quantitative assessments applied to provinces and territories under the benchmark, the time frame considered for the main quantitative analysis is the 2023–2030 period. However, additional modelling has also been conducted to estimate expected impacts of the amendments in 2031 and 2032, to account for 10 years of impacts, as recommended by Treasury Board Secretariat (TBS) guidance. Without further regulatory amendments, in 2031 and 2032 the annual tightening rates for the OBSs are maintained at the same rates at which they are set for the 2023–2030 period, and the excess emissions charge remains at $170 per tonne of CO₂e, in the Regulatory Scenario.

Figure 1: Logic model for the analysis of the amendments
Amendments	→	Reduction in domestic GHG emissions	→	Reduction in climate change damages	→	Societal benefits
Amendments	→	Net compliance costs	→	Reduction in economic output	→	Household welfare costs
Amendments	→	Redistribution of compensation obligation proceeds	→	Increased proceeds returned to backstop jurisdictions	→	Reduction in household welfare costs

Baseline Scenario: Modelling of the baseline case was conducted using an adjusted 2022 Reference Case (Canada’s official emissions forecast), and an increasing fuel charge ($170 per tonne of CO₂e in 2030). In addition, non-backstop jurisdictions are assumed to be operating within a separate, linked carbon pollution pricing system that is aligned with the federal benchmark, while backstop jurisdictions maintain the excess emissions charge to $50 per tonne of CO₂e, and do not apply tightening rates to OBSs. The Baseline Scenario includes clearly articulated policies from the ERP and Budget 2022–2023 that have been announced, funded, and are directed towards a specific sector. The Baseline Scenario excludes policies that are not defined and do not have sector-specific targets. It includes federal environmental regulations that were published in the Canada Gazette, Part II, ahead of the publication of the amendments in the Canada Gazette, Part II.

Regulatory Scenario: Under the Regulatory Scenario, modelling was conducted using the 2022 Reference Case as described in the “Baseline Scenario” section, with the addition of an excess emissions charge that increases at $15 per tonne of CO₂e per year, resulting in a carbon price of $170 per tonne of CO₂e in 2030, and maintaining this price in 2031 and 2032. The scenario also includes the previously described tightening rates for OBSs starting in 2023, where the OBSs are tightened by 2% per year starting in 2023, with exceptions for sectors that are deemed to be at a very high risk of carbon leakage and competitiveness impacts. For these sectors, a tightening rate of 1% per year was applied. As with the Baseline Scenario, the Regulatory Scenario includes policies and regulations that are fully legislated, funded or published in the Canada Gazette, Part II.

Sensitivity analysis: Given potential uncertainty due to various assumptions, sensitivity analysis was conducted to assess the impact of changes to the parameters related to the expected benefits and costs of the amendments, where possible. A range was assumed for estimated GHG emission reductions where the reductions are potentially 25% lower or 25% higher than anticipated. In the event the impact to household welfare is lower or higher than the estimated costs, a range of 25% lower and 25% higher was selected to account for potential uncertainty. The level to which the redistribution of compensation obligation proceeds will lower the cost impacts on household welfare is uncertain; however, it is assumed to be lower than estimated. Three scenarios were established to reflect this uncertainty, a high estimate (100% of the compensation obligation), a central estimate (25% below the full compensation obligation), and a low estimate (50% below the full compensation obligation).

Incremental impacts: The analysis compares the expected impacts of the Regulatory Scenario relative to the Baseline Scenario. This analysis does not assess the impacts of carbon pollution pricing as a whole. It assesses the incremental impacts of increasing the excess emissions charge to $170 per tonne of CO₂e by 2030 and remaining at $170 per tonne of CO₂e after 2030, and tightening rates for OBSs starting in 2023, where the OBPS currently applies.

Monetary results: All monetary results are presented in 2022 Canadian dollars, and non-2022 prices were adjusted using consumer price index (CPI) deflators from Energy-Emissions-Economy Model for Canada (E3MC), the Department’s macroeconomic model. When shown as present values, future year impacts have been discounted at 2% per year, consistent with TBS guidance for health and environmental regulatory proposals, to 2023 (the base year of the analysis).

Social cost of greenhouse gases: As illustrated in Canada’s Cost-Benefit Analysis Guide for Regulatory Proposals published by TBS, when conducting regulatory analysis, federal departments and agencies must use the SC-GHG to measure the costs and benefits associated with changes in emissions. In this analysis all GHGs were measured in tonnes of CO₂e. Therefore, only the social cost of carbon (SCC) was applied to the GHG emissions presented here.

Modelling: The Baseline Scenario and the Regulatory Scenario have been modelled using EC-Pro. As the amendments is expected to affect production in various markets in the Canadian economy, a general equilibrium model is best suited to estimate the impacts.^{footnote 20} EC-Pro is able to assess a number of variables, including GHG emissions, household economic welfare, GDP and gross value added (GVA).

Emission changes that are attributable to technological change resulting in combustion emissions abatement are modelled through responsiveness of production inputs to changes in relative prices. For example, a representative producer may switch to lower emitting fuels in the model in response to the amendments. For the modelling of non-combustion emissions, it is assumed that facilities could make a technological change to lower their costs under the OBPS. Combustion and non-combustion GHG emission changes can also be attributable to changes in production.

Under the OBPS, the facility emissions limit is calculated by multiplying the production from an industrial activity by the OBS applicable to that activity. These standards are calculated by taking a percentage of the historic production weighted average emissions intensity for an industrial activity. If GHGs emitted from a covered facility are below the facility emissions limit, surplus credits will be issued to the covered facility. If GHGs emitted from a covered facility are above the facility emissions limit, it has a compensation obligation. The model accounts for the supply and demand balance of credits by assuming that facilities that emit below their annual facility emissions limit earn the value of the excess emissions charge for each tonne between their actual emissions and their limit so long as the total quantity of compensation obligations under the OBPS exceeds the quantity of surplus credits in a given year. Should the supply of surplus credits exceed the compensation obligation in the entire market, the model will estimate a lower marginal (market-clearing) price and thus a lower incentive for emission reductions. The model does not account for trading partners for these credits or banking behaviour.

Benefits

Reduction in greenhouse gas emissions

Benefits will result from decreases in GHG emissions relative to the Baseline Scenario, which are expected to reduce damages from climate change and thus provide global societal benefits. Table 5 shows the expected incremental decreases in GHG emissions from the amendments.

Table 5: GHG emissions reductions resulting from the amendments over the 2023–2032 period (Mt of Co2e)
Year	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032	Total
Decrease in GHG emissions (Mt of CO₂e)	0.029	0.063	0.112	0.167	0.210	0.281	0.422	0.576	0.669	0.806	3.335

To take into account uncertainty related to GHG emissions reductions, a sensitivity analysis considers emissions reductions of the amendments up to 25% lower or 25% higher than the central estimate. In the sensitivity analysis, the total incremental decrease in GHG emissions ranges from 2.5 Mt of CO₂e to 4.1 Mt of CO₂e over the analytical period.

Carbon leakage

In the Regulatory Scenario, there is an increased risk of domestic production shifting to foreign jurisdictions due to increased production costs attributable to the amendments. While the purpose of the OBPS system is to address this issue, the extent to which these shifts in production could lead to an increase in foreign GHG emissions depends on the emissions intensity of the facilities where production is relocated and the associated quantities of production, both of which are unknown. The Regulatory Scenario only accounts for incremental decreases in GHGs in Canada and, therefore, could overestimate the global net emissions reductions in the event of carbon leakage.

Social cost of greenhouse gases

The main role of the social cost of greenhouse gases, and in this case the SCC, as it is used in Canada, is to inform cost-benefit analyses of environmental regulations. Climate change is expected to result in a range of impacts, which include drought, floods, agricultural production and energy use changes, and effects on human health and ecosystem services. All of these impacts result in costs to society, which, when aggregated, can represent amounts in the billions of dollars. The SCC reflects the cost of these expected impacts, measuring the global damages resulting from each additional tonne of CO₂ emitted in the atmosphere today over its lifetime.

The SCC includes damages that have impacts on agricultural production, human health, flood risk, disruption of energy systems, and ecosystem services. However, some other impacts related to climate change, including extreme weather events such as storms, wildfires and hurricanes, ocean acidification, national security risks, and interactions/feedback across sectors, are not yet sufficiently well understood to be fully integrated into models currently used to assess global climate change impacts. The SCC therefore reflects only a portion of the impacts that can be expected from climate change and therefore could be interpreted as being a lower bound of the potential impacts from climate change.

In December 2022, the Department published Social Cost of Greenhouse Gas Estimates — Interim Updated Guidance for the Government of Canada, which updated the SCC values used in proposed policies, regulations, or proposed projects. The SCC estimate for the year 2023 is $279 per tonne of CO₂e (2022 Canadian dollars) and increases each year to account for increasing damages over time. The updated estimates are identical to those adopted by the United States Environmental Protection Agency (U.S. EPA) in its draft technical update, converted to Canadian currency in constant 2021 dollars, and have been updated to 2022 dollars for this analysis, as demonstrated in Table 6.^{footnote 21}

Table 6: Updated social cost of carbon (2023–2032, $/tonne of CO2e, 2022 Canadian dollars)
Year	Social cost of carbon
2023	$279
2024	$284
2025	$289
2026	$294
2027	$299
2028	$304
2029	$309
2030	$314
2031	$319
2032	$324

Results from the application of the new SCC to the emissions reductions estimated from the amendments are presented in Table 7. The total present value of societal benefits is estimated at $910 million from 2023 to 2032.

Table 7: Present value benefits resulting from greenhouse gas emissions reductions from the amendments (2023–2032, millions of Canadian dollars)
Year	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032	Total
Societal benefits resulting from emissions reductions	8	17	31	46	58	77	115	157	183	218	910

In the sensitivity analysis, the total incremental benefits to Canadian society from a reduction in GHG emissions range from $680 million to $1,140 million from 2023 to 2032.

Reductions in air pollutants

EC-Pro was chosen to model the amendments because it takes into consideration the macro-economic impacts of the amendments. However, air pollutant emissions are not currently an output of this model. Thus, while these impacts are not quantified, as the amendments will reduce GHG emissions, it is expected that this will also reduce air pollutants which will have a positive overall effect on air quality. Relative to the Baseline Scenario, the Regulatory Scenario is expected to result in reductions in these pollutants and therefore result in air quality benefits in certain locations in Canada.

Costs

As a result of the amendments, domestic production is estimated to be lower in the Regulatory Scenario (in which the amendments apply) than it is in the Baseline Scenario. The costs incurred by covered sectors, facilities, and activities may decrease domestic production and domestic demand. The resulting net decrease in production could in turn decrease the disposable income of households, who are assumed to be the owners of the factors of production, labour, and capital, through decreases in the wages earned by workers and the profits earned by firms. Households may choose to allocate the lower levels of disposable income to other goods and services to maximize their welfare.

A recommended measure of welfare in a general equilibrium model (EC-Pro) is equivalent variation (EV), which is based on the concept of willingness-to-pay, or the maximum amount a household will pay for a particular good or service given its budget constraint.^{footnote 22} The change in EV from the Baseline Scenario to the Regulatory Scenario represents the maximum amount of money that households are willing to pay to avoid the welfare losses associated with the implementation of the Regulatory Scenario.^{footnote 23,}^{footnote 24} This amount can be considered equivalent to the change in welfare for households from the decrease in consumption under the Regulatory Scenario.

As demonstrated in Table 8 below, between 2023 and 2032, the total present value of household welfare costs attributed to the amendments is estimated at $535 million.

Table 8: Present values of household welfare costs resulting from the amendments (2023–2032, millions of Canadian dollars)
Year	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032	Total
Household welfare costs	5	12	22	31	42	53	71	88	98	113	535

Given the uncertainty around the average cost of abatement for covered facilities, a sensitivity analysis considers costs up to 25% lower or 25% higher than the central cost estimate. In the sensitivity analysis, the total costs range from $400 million to $670 million.

Federal compensation proceeds redistribution

Under the OBPS, federal proceeds collected from the backstop jurisdictions are returned directly through federal programming to support low-carbon technology at OBPS facilities in backstop jurisdictions, or directly to these provinces and territories. However, in the CGE modelling analysis, compensation proceeds collected by the federal government are assumed to be distributed to all Canadian households. This assumption was made to isolate emissions reductions associated with the regulatory changes, including the price and tightening rate, and exclude any additional emissions reductions that would be achieved through proceeds returned in the form of federal programming. Therefore, in practice, household welfare would be higher for these jurisdictions relative to cost impacts estimated by the model. To address this discrepancy, a post-modelling adjustment was made where compensation proceeds were distributed to backstop jurisdictions only.

The incremental proceeds from the federal OBPS compensation obligations that would be redistributed to backstop jurisdictions are estimated to be between $175 million and $350 million, with a central estimate of $265 million. These estimates of incremental redistribution are based on changes in compensation proceeds (i.e. compensation obligation payments) between the Baseline and Regulatory Scenarios. In the Baseline Scenario, it is assumed that covered facilities would pay $50 per tonne of CO₂e on all emissions above their emissions limits (compensation obligation). In the Regulatory Scenario, it is assumed that covered facilities would pay the applicable excess emissions charge on their compensation obligation. However, compensation proceeds are not expected to equal redistribution exactly, as the analysis does not account for potential decreases in economic activity that could be associated with carbon pricing. As such, to be conservative, the central estimate of redistribution is assumed to be 25% lower than the original compensation proceeds estimate. The sensitivity analysis then uses the original compensation proceeds estimate for the upper bound of redistribution, and a 50% lower estimate for the lower bound of redistribution. Table 9 summarizes these estimates by year.

Table 9: Benefits to backstop jurisdictions from compensation proceeds redistribution (2023–2032, millions of Canadian dollars)
Estimates of redistribution	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032	Total (present value)
High estimate (100% of the compensation obligation)	5	12	19	29	39	51	53	52	50	43	$350
Central estimate (25% below the full compensation obligation)	4	9	15	21	30	38	40	39	38	32	$265
Low estimate (50% below the full compensation obligation)	3	6	10	14	20	26	26	26	25	21	$175

Streamlined requirements for Output-Based Pricing System participation

The amendments facilitate OBPS participation through the inclusion of additional industrial activities recognized by the Minister; the List of additional industrial activities will be published on the Department’s OBPS web page. The amendments also harmonize requirements for opt-in facilities through changes made to calculated OBSs and changes to the process for voluntary participation. The streamlined process enables the Minister to broaden opt-in eligibility to facilities engaged in additional industrial activities and could also increase the participation level of opt-in facilities, depending on the scope of where the OBPS applies. Increased participation may result in lower reductions in GHG emissions, and an increase in economic activity, but will lower costs for those facilities moving into the OBPS from a fuel charge regime. However, based on the current scope of application of the OBPS, no new voluntary participants are expected. Therefore, no incremental impacts are anticipated from these changes at this time.

Administrative costs to Government

Additional costs may accrue to the Department related to updating the electronic system to meet the various new requirements related to the amendments. There will be an estimated one-time expense of approximately $295,000 in the 2023–2024 fiscal year. This includes $95,000 for updating registration and reporting and up to $200,000 for updates to the credit and tracking system.

Distributional analysis

Cost impacts by jurisdiction

The magnitude of the impacts that are attributable to the amendments may disproportionately affect certain jurisdictions compared to others. By 2032, it is estimated that the amendments will result in a cumulative decrease in societal welfare in backstop jurisdictions compared to the Baseline Scenario in which the excess emissions charge and stringency of the OBPS do not change. The most significant impacts to welfare stem from affected activity in Nunavut. Approximately 61% of the total household welfare costs are expected to accrue in Nunavut while only 16% of total expected GHG emissions reductions occur in the territory. Nunavut faces disproportionately high welfare costs as modelling analysis shows the territory having high estimated OBPS compensation costs (in the mining and ore processing sector) due to its limited access to low-cost emissions reductions.

While any modelling exercises of potential future impacts are highly dependent on underlying forecasts, given the limited scope of the OBPS, the resulting distribution is especially dependent on forecasted future emissions intensities and technology deployment of relatively few economic sectors in relatively economically small jurisdictions. As underlined above, the estimated supply and demand of compensation obligations across economic sectors, and as a result across provinces and territories, is acutely sensitive to changes in underlying forecasted values in the Baseline Scenario. Therefore, the results show one possible outcome of the environmental and economic distributional impacts resulting from the amendments.

Table 10: Distribution of impacts by jurisdiction
Province and territory	Percentage of total GHG emissions reduced by jurisdiction	Percentage of total household welfare costs by jurisdiction
Manitoba	74%	25%
Prince Edward Island	7%	10%
Yukon	2%	5%
Nunavut	16%	61%

Summary of benefits and costs

From 2023 to 2032, there is an expected decrease in GHG emissions of between 2.5 million and 4.1 million Mt of CO₂e, with a central estimate of 3.3 Mt of CO₂e. Using the Department’s updated value of the SCC (2022 Canadian dollars), this decrease in GHG emissions is expected to benefit Canadian households by approximately $685 million to $1,140 million, with a central estimate of $910 million, as a result of avoided costs of damages related to climate change. The amendments are expected to decrease Canadian household welfare from 2023 to 2032 by between $400 million and $670 million, with a central estimate of $535 million, as a result of decreased domestic output and decreased consumption. The redistribution of federal proceeds collected from compensation obligations from 2023 to 2032 to households is expected to offset the costs to household welfare by $175 million to $350 million, with a central estimate of $265 million. Therefore, the total costs associated with the amendments could lower Canadian household welfare by $225 million to $315 million, with a central estimate of $270 million. Overall, it is estimated that the amendments will result in net benefits of approximately $640 million over the 2023 to 2032 period.

Cost-benefit statement

Number of years: 10 (2023–2032)
Price year: 2022
Base year: 2023
Discount rate: 2%

Table 11: Monetized benefits (2023–2032)
Impacted stakeholder	Description of monetized benefit	Base year (2023) [present value]	Final year (2032) [present value]	Total (present value)	Annualized value
Industry	Net reductions in administrative costs for covered facilities^{table e8 note a}	$280	$22,000	$185,000	$20,500
Canadians	Societal benefits of reduced GHG emissions	$8 million	$218 million	$910 million	$101 million
All stakeholders	Total benefits	$8 million	$218 million	$910 million	$100 million
Table e8 note(s) Table e8 note a These projected net reductions in administrative costs are described in the "One-for-one rule" section below. Return to table e8 note a referrer

Table 12: Monetized costs (2023–2032)
Impacted stakeholder	Description of cost	Base year (2023) (present value)	Final year (2032) (present value)	Total (present value)	Annualized value
Government	Federal government administrative costs	$295,000	N/A	$295,000	$32,000
Canadians in backstop jurisdictions	Decrease to household welfare	$5 million	$113 million	$535 million	$60 million
Canadians in backstop jurisdictions	Redistributed federal proceeds from compensation obligation	−$4 million	−$32 million	−$265 million	−$30 million
All stakeholders	Total costs	$1 million	$81 million	$270 million	$30 million

Table 13: Summary of monetized costs and benefits (2023–2032)
Impacts	Base year (2023) [present value]	Final year (2032) [present value]	Total (present value)	Annualized value
Total costs	$1 million	$81 million	$270 million	$30 million
Total benefits	$8 million	$218 million	$910 million	$100 million
NET IMPACT	$7 million	$137 million	$640 million	$70 million

Qualitative impacts (non-monetized)

Positive impacts:

Improved air quality for Canadians (2023–2032)
Ensures the OBPS is national in scope and can apply anywhere in Canada, if required

Negative impacts:

Increased risk of domestic production shifting to foreign jurisdictions

Small business lens

Analysis under the small business lens concluded that the amendments will not impact Canadian small businesses. The OBPS is designed to allow smaller facilities located in backstop jurisdictions to voluntarily apply to participate in the OBPS. Based on the facilities that are currently covered by the OBPS, including voluntary participants, no businesses are considered a small business as defined by annual revenue data. Changes to enable the recognition of additional industrial activities, and to the method for calculating an OBS combined with changes to the Opt-in Policy, could lower the burden for smaller facilities to opt in. However, since the OBPS has been in place for a number of years in existing backstop jurisdictions and, in general, facilities have an incentive to voluntarily participate, most eligible facilities have likely already applied to participate in the OBPS. Therefore, given the current scope of application of the OBPS, no new entrants, including small businesses, are expected over the analytical timeline as a result of the amendments.

One-for-one rule

The one-for-one rule applies since there will be an incremental decrease in administrative burden on business. The amendments make no change in terms of federal regulatory titles.

There will be a one-time administrative cost for covered facilities to familiarize themselves with the new administrative provisions introduced by the amendments. There will also be ongoing administrative activities from 2023 to 2032 that are additional to existing administrative activities, including activities related to information gathering to recalculate OBSs, reporting, verification for facilities engaging in a new activity, additional site visits by verification bodies and record-keeping.

On the other hand, the amendments remove some existing administrative activities from the Regulations related to quantification and correcting reports. The amendments remove detailed quantification methods from Schedule 3 to the Regulations; these methods are specified in a technical document incorporated by reference into the Regulations. This will facilitate updates to the quantification methods and will provide the opportunity to improve harmonization of GHG quantification requirements with other GHG reporting programs such as the GHGRP, which is expected to reduce duplication of work. In addition, the amendments remove the obligation to submit a corrected report when any error or omission in an annual report is identified by the person responsible for a covered facility. Instead, a corrected report is only required when the person responsible identifies an error or omission that would have constituted a material discrepancy if it had been found during the verification of the annual report.

Based on a set of assumptions on time needed to conduct various administrative activities, and an estimated hourly cost of labour of $50 per hour (in 2012 Canadian dollars), the amendments are estimated to result in a net decrease in administrative burden of approximately $7,300 in annualized average costs across all covered facilities from 2023 to 2032.^{footnote 25,}^{footnote 26} Decreases in net administrative impacts per installation are projected to be, on average, 5.5 hours per year for 37 facilities, corresponding to the removal of about $200 in annualized costs per facility.

Regulatory cooperation and alignment

Canada is working in partnership with the international community to implement the Paris Agreement, an accord intended to reduce GHG emissions, to limit the rise in global average temperature to less than 2 °C above pre-industrial levels, and to pursue efforts to limit the temperature increase to 1.5 °C. As part of its commitments made under the Paris Agreement, Canada had previously pledged to reduce national GHG emissions by 30% below 2005 levels by 2030. On July 12, 2021, the Minister formally submitted Canada’s enhanced nationally determined contribution to the United Nations, committing Canada to reduce national GHG emissions by 40% to 45% below 2005 levels by 2030. To meet these commitments, the federal government is implementing a series of measures, including continuing to put a price on carbon pollution. To achieve these goals, a number of GHG reduction measures have been implemented or proposed, including the amendments.

This international partnership relates to the overall goals and outcomes of climate action but does not prescribe the targets that were committed to by each country or how each country should reduce its emissions. Other countries are taking a variety of approaches, some of which include carbon pricing. As discussed earlier, carbon leakage is a significant risk since carbon pricing policies are not in place for the majority of global emissions, resulting in uneven carbon costs across jurisdictions. The OBPS is one of several types of systems that can maintain a carbon price signal while helping protect against competitiveness and carbon leakage risks.

Domestically, under the Pan-Canadian Approach, provinces and territories have the flexibility to implement a carbon pricing system aligned with federal benchmark criteria that makes sense for their circumstances, either an explicit price-based system, such as a carbon tax or charge, and a performance-based emissions system for large industrial emitters, or a cap-and-trade system. The federal OBPS is a component of the federal carbon pricing backstop and applies in any province or territory that requests it or that does not have a carbon pricing system in place that meets the federal benchmark criteria. The introduction of OBS tightening rates plays an important role in aligning the federal OBPS with the updated federal benchmark.

Strategic environmental assessment

The Department conducted strategic environmental assessments (SEA) in 2017, 2018, 2019, and 2021 for elements of its carbon pollution pricing policies.

In the 2021 SEA, it was noted that the federal carbon pricing system is expected to result in important, positive environmental effects, reduce GHG emissions and energy use and support the implementation of Canada’s Strengthened Climate Plan: A Healthy Environment and a Healthy Economy, by promoting the adoption of clean technology and the transition to a low-carbon economy. As the amendments are a component of the carbon pricing pollution system, it therefore aligns with Canada’s Federal Sustainable Development Strategy, particularly with the goals of “Effective action on climate change,” “Clean growth,” “Modern and resilient infrastructure,” “Clean energy,” and “Safe and healthy communities.” The amendments centrally contribute to efforts to meet Canada’s new, more ambitious 2030 emissions target and achieve net-zero GHG emissions by 2050. It also contributes to multiple Sustainable Development Goals (SDGs) including SDG 3 — “Good Health and Well-Being”; SDG 7 — “Affordable and Clean Energy”; SDG 9 — “Industry, Innovation and Infrastructure”; SDG 11 — “Sustainable Cities and Communities”; SDG 12 — “Responsible Consumption and Production”; SDG 13 — “Climate Action”; and SDG 17 — “Partnerships for the Goals”.

Gender-based analysis plus

A gender-based analysis plus (GBA+) was undertaken for the Government of Canada’s existing carbon pricing initiatives. This GBA+ identified that climate change has far-reaching health, economic and environmental impacts on all Canadians, but these effects are and will be felt most acutely by those segments of the population that are already vulnerable owing to geography, gender, age, Indigenous identity, minority status and disability. Climate change policy can exacerbate these effects, depending on the design.

As climate change has the potential to affect the economy, health and safety, social cohesion and the environment, addressing climate change could have a positive impact on all quality of life domains. Vulnerable groups may feel more of these positive impacts because they are disproportionately affected by climate change. These groups include northern and coastal regions and communities, indigenous communities, people with disabilities, people with existing health conditions, infants and children, the elderly, women, and low-income communities.

Additionally, workers in potentially affected sectors are typically male, and college educated. For example, Statistics Canada estimates that, in 2019, men accounted for 75% of mining, oil and gas workers in Canada. Negative impacts on the workforce in large industrial sectors could be offset by funds returned to provinces if provinces choose to use these funds to help decarbonize existing industry and support jobs in low-carbon industries.

Rationale

Excess emissions charge without the amendments

Under the proposed Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations, the Department conducted an assessment to illustrate the impacts of the current carbon price trajectory for the excess emissions charge without the amendments. In the event that the tightening rates are not implemented, in any jurisdiction, while the excess emissions charge increases over time to $170 per tonne of CO₂e in 2030, fewer GHG emission reductions would be expected. The amendments are thus required in order to allow the federal OBPS to align with the updated Pan-Canadian Approach. This conclusion is further explained below.

If there were no increases in the stringency of the OBSs over time, the market for compliance units, including surplus credits, would be expected to weaken through a relative increase in the supply of surplus credits relative to demand. For the emissions trading market to remain effective and for the OBPS to achieve the reductions expected, the marginal price signal must be maintained at the minimum national carbon pollution price. This is expected to be the case when there is a net demand for compliance units in the emissions trading market, that is when the total compensation obligation of covered facilities exceeds the total quantity of all types of compliance units available.

The marginal price incentive created by the OBPS is a crucial decision factor for firms investing in GHG emission reductions. The post-2022 carbon price trajectory sends a strong price signal to reduce emissions. However, this price level is not the only determinant of the marginal price signal, which reflects the market price of surplus credits generated by covered facilities that emit less than their respective emissions limit. As covered facilities plan decarbonization investments, the future market price of any surplus credits that they will be able to generate or purchase is an important factor, because it represents a revenue stream that can help fund or cover the cost of projects, or an avoided compliance cost that can reduce compensation obligations. As the excess emissions charge increases and other policies and programs are implemented, and improvements in technologies and operations are made, the level of GHG emissions from covered facilities is anticipated decreasing. If the stringencies of the OBSs do not increase but remain constant, a decrease in the GHG emissions from covered facilities will increase the quantity of surplus credits available to buyers (other covered facilities). This will likely result in a marginal (market-clearing) price of surplus credits that is noticeably lower than the excess emissions charge. In this scenario, the incentive for covered facilities to reduce their emissions would be lessened, as the market price of surplus credits would be expected to be lower than the excess emissions charge.

Finally, an OBPS with a relatively low price for compliance units would not be consistent with the updated federal benchmark that specifically requires provincial and territorial output-based pricing systems to be designed to maintain a marginal price signal equivalent to the minimum national price on carbon pollution for explicit price-based systems across all covered emissions.

Implementation, compliance and enforcement, and service standards

Implementation

The amendments are set to come into force on the day on which they are registered, with several exceptions. The following changes to the Regulations, which are referred to in the Minister’s notice of intent published on October 28, 2022, and explained in the “Description” section, are deemed to come into force on January 1, 2023:

incorporation of an annual tightening rate of 2% to most OBSs;
incorporation of an annual tightening rate of 1% to the OBSs for activities in sectors at very high risk of competitiveness impacts and carbon leakage impacts resulting from carbon pricing;
updates of some OBSs due to changes in the global warming potentials (GWP) in Schedule 3 to the Act and clarification of the applicable GWP for a compliance period;
changes to the requirements for calculated OBSs; and
incorporation of an exemption for remote electricity generation facilities that generate electricity from liquid or gaseous fuels for distribution to remote communities.

The following changes explained in the “Description” section will come into force on January 1, 2024:

removing GHG quantification methods from Schedule 3 to the Regulations and incorporating by reference the Quantification Methods;
introduction of requirements for measuring devices used in the quantification of GHGs and changes to requirements related to devices used in the quantification of production, including for electricity generation facilities;
addition of new industrial activities and OBSs to Schedule 1 to the Regulations and revision of certain activity descriptions and OBS values;
changes to the materiality threshold in the verification process for the quantification of GHG emissions;
changes to the scope of coverage of a covered facility; and
clarification of the scope of the complexity weighted barrel (CWB) quantification requirements.

In determining if a change to the Regulations should come into force retroactively, the Department considered (i) whether the regulatory change impacts the submission of annual reports for the 2022 compliance period; (ii) whether it is necessary to align with federal benchmark criteria; and (iii) whether it is anticipated to significantly enhance the implementation of the Regulations or reduce regulatory costs for covered facilities.

A number of policies and guidance documents will be updated and posted on the Department’s OBPS web page to support the implementation of the amendments. These include a policy that guides decisions to recognize sectors and activities at risk of carbon leakage and competitiveness impacts, a list of additional industrial activities that would be updated annually and the revised Opt-in Policy describing the streamlined process enabled by the amendments. In addition, the Quantification Methods document will be updated regularly.

The Department will continue to communicate compliance promotion material relevant to the amendments and to the OBPS in general to persons responsible for covered facilities by email. The Department also makes periodic updates to the Government of Canada’s OBPS web page to provide useful information concerning regulatory requirements. In addition, the Departmental staff responsible for the implementation of the federal OBPS work closely with their counterparts from the Canada Revenue Agency (CRA) and the GHGRP to ensure the effective implementation of certain amendments.

Compliance and enforcement

Departmental officials will undertake actions to implement and enforce the amendments, as necessary, in accordance with the Department’s compliance and enforcement policies.^{footnote 27} Enforcement officers will apply the principles found in the compliance and enforcement policies when verifying compliance. These policies set 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 will choose the appropriate enforcement action based on the policies.

Contacts

Katherine Teeple
Executive Director
Industrial Greenhouse Gas Emissions Management Division
Carbon Markets Bureau
Environmental Protection Branch
Department of the Environment
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: tarificationducarbone-carbonpricing@ec.gc.ca

Matthew Watkinson
Executive Director
Regulatory Analysis and Valuation Division
Economic Analysis Directorate
Strategic Policy Branch
Department of the Environment
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: RAVD.DARV@ec.gc.ca

Footnotes

Footnote a

S.C. 2018, c. 12, s. 186

Return to footnote a referrer

Footnote b

S.C. 2019, c. 28, s. 180

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Footnote c

S.C. 2009, c. 14, s. 126

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Footnote 1

SOR/2019-266

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Footnote 2

SOR/2017-109

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Footnote 3

Update to the Pan-Canadian Approach to Carbon Pollution Pricing 2023–2030

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Footnote 4

The Canadian Greenhouse Gas Offset Credit System Regulations were published in the Canada Gazette, Part II, on June 8, 2022.

Return to footnote 4 referrer

Footnote 5

EC-Pro is a computable general equilibrium (CGE) model maintained by the Department. Refer to the benefits and costs section for a more detailed description.

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Footnote 6

When applied to determine emissions reduction factors, the analysis assumed a starting rate for all OBSs of 80% of the national production weighted average emissions intensity of the sector (i.e. on average, facilities in the sector would face carbon costs on 20% of their emissions), and a carbon price of $50 per tonne of CO2e in 2022. In addition to adjustments informed by the three-phased analysis of risks of carbon leakage and adverse competitiveness impacts, OBSs were also adjusted for sectors with industrial process emissions constituting 30% or more of total GHG emissions at the sector level.

Return to footnote 6 referrer

Footnote 7

The tightening rates apply a fixed annual percentage reduction to the OBS to which it applies. For example, if the standard for an activity were set at 100 tonnes of CO2e per unit of production and were subject to a 2% tightening rate, the standard for that activity would be 98 tonnes per unit of production in 2023 and 96 tonnes per unit of production in 2024, and so forth.

Return to footnote 7 referrer

Footnote 8

Review of the Federal Output-Based Pricing System Regulations

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Footnote 9

Review of the OBPS Regulations: Consultation Paper

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Footnote 10

Report 5 of the Commissioner of the Environment and Sustainable Development to the Parliament of Canada: Carbon Pricing — Environment and Climate Change Canada (PDF)

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Footnote 11

Historical information used was data from 2017 to 2019. The carbon price applied was adjusted for inflation; therefore, the 2026 carbon price was $95.13 (CAD 2018).

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Footnote 12

The EI and TE thresholds to determine when a sector is at low competitive risk are: EI ≥ 1% and < 3%, if TE < 10% or EI < 1%.

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Footnote 13

The EI and TE thresholds to determine when a sector is at medium competitive risk are: EI ≥ 3% and < 30%, if TE < 10%; EI ≥ 1% and < 15%, if TE ≥ 10% and < 20%; or EI ≥ 1% and < 3%, if TE ≥ 20%.

Return to footnote 13 referrer

Footnote 14

The EI and TE thresholds to determine when a sector is at high competitive risk are: EI ≥ 30%, if TE < 10%; EI ≥ 15%, if TE ≥ 10% and < 20%; EI ≥ 3% and < 10%, if TE ≥ 20% and < 40%; or EI ≥ 3% and < 6%, if TE ≥ 40% and < 80%.

Return to footnote 14 referrer

Footnote 15

The EI and TE threshold to determine when a sector is at very high competitive risk is: EI ≥ 10%, if TE ≥ 20% and < 40%; EI ≥ 6%, if TE ≥ 40% and < 80%; or EI ≥ 3% and TE ≥ 80%.

Return to footnote 15 referrer

Footnote 16

Canada Gazette, Part II, Volume 156, Number 22: Order Amending Schedule 3 to the Greenhouse Gas Pollution Pricing Act; Canada Gazette, Part II, Volume 156, Number 22: Order Amending Schedule 4 to the Greenhouse Gas Pollution Pricing Act

Return to footnote 16 referrer

Footnote 17

Social Cost of Greenhouse Gas Estimates — Interim Updated Guidance for the Government of Canada

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Footnote 18

Canadian Cost-Benefit Analysis Guide : Regulatory Proposals

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Footnote 19

The Department uses its Energy-Emissions-Economy Model for Canada (E3MC) macroeconomic model to develop the Reference Case, which is updated annually to integrate current macroeconomic assumptions, including new provincial, territorial, and federal policies (fully legislated and funded), and technological changes and advances.

Return to footnote 19 referrer

Footnote 20

For further information on the use of general equilibrium modelling to calculate the impacts of regulations, refer to the following sources: (a) Guidelines for Preparing Economic Analyses (2016), chapter 8; (b) Teaching Benefit-Cost Analysis, edited by Scott Farrow (2018), chapter 5: “Partial Equilibrium versus General Equilibrium Evaluations or Small versus Large Projects”; and (c) “Welfare Analysis: Bridging the Partial and General Equilibrium Divide for Policy Analysis,” by Scott Farrow and Adam Rose; Journal of Benefit Cost Analysis (2018).

Return to footnote 20 referrer

Footnote 21

The U.S. EPA’s draft guidance is undergoing review by an external expert peer-review panel, with a formal update to the U.S. EPA guidance anticipated by fall 2023 or winter 2024.

Return to footnote 21 referrer

Footnote 22

Guidelines for Preparing Economic Analysis. United States Environmental Protection Agency.

Return to footnote 22 referrer

Footnote 23

Boadway, R. and Neil, B. “Welfare Economics.” Basil Blackwell Publisher Limited, Oxford, 1984.

Return to footnote 23 referrer

Footnote 24

Varian, H. “Microeconomic Analysis, Third Edition.” W. W. Norton & Company, New York, 1992.

Return to footnote 24 referrer

Footnote 25

In accordance with Canada’s Red Tape Reduction Regulations, cost estimates under the one-for-one rule are calculated using a 10-year analytical period, 2012 Canadian dollars, a 7% discount rate, and a discounting base year of 2012.

Return to footnote 25 referrer

Footnote 26

The non-rounded decrease in annualized average administrative costs is estimated to be $7,373 or $199 per covered facility.

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Footnote 27

Environmental compliance and enforcement policies

Return to footnote 27 referrer

Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations: SOR/2023-240

Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations

Output-Based Pricing System Regulations

Environmental Violations Administrative Monetary Penalties Regulations

Coming into Force

SCHEDULE

SCHEDULE 3

Quantification Requirements

PART 1 Bitumen and Other Crude Oil Production

PART 2 Bitumen and Heavy Oil Upgrading

PART 3 Petroleum Refining

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production

PART 3.1 Surface mining of oil sands and extraction of bitumen

PART 4 Natural Gas Processing

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production

PART 5 Natural Gas Transmission

DIVISION 1 Quantification of Emissions

DIVISION 2

PART 6 Hydrogen Gas Production

PART 7 Cement and Clinker Production

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production

PART 8 Lime Manufacturing

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production

PART 9 Glass Manufacturing

PART 10 Gypsum Product Manufacturing

PART 11 Mineral Wool Insulation Manufacturing

PART 12 Brick Production

PART 13 Ethanol Production

PART 14 Furnace Black Production

PART 15 2–methylpentamethylenediamine (MPMD) Production

PART 16 Nylon Production

PART 17 Petrochemicals Production

PART 18 Vaccine Production

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production

PART 19 Scrap-based steel production

PART 20 Integrated Steel Production

PART 21 Iron Ore Pelletizing

PART 22 Metal Tube Manufacturing

PART 23 Base Metal Production

PART 24 Potash Production

PART 24.1 Production of Evaporated Salt

PART 25 Coal Mining

PART 26 Production of Metals or Diamonds

PART 27 Char Production

PART 28 Activated Carbon Production

PART 29 Nitrogen-based Fertilizer Production

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production

PART 30 Industrial Potato Processing

PART 31 Industrial Oilseed Processing

PART 32 Alcohol Production

PART 33 Wet Corn Milling

PART 34 Citric Acid Production

PART 35 Sugar Refining

PART 35.1 Production of Malt

PART 36 Pulp and Paper Production

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production

PART 37 Main Assembly of Vehicles

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production

PART 38 Electricity Generation

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production — Main Industrial Activity

DIVISION 3 Secondary Industrial Activity – Quantification of Production

PART 39 Production of wood products

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production

PART 40 Aluminium production from alumina

PART 41 Production of baked anodes — Aluminium

PART 42 Production of calcined petroleum coke — Aluminium

PART 43 Production of alumina from bauxite

DIVISION 1 Quantification of Emissions

DIVISION 2 Quantification of Production

PART 44 Production of pneumatic tires

PART 1
Bitumen and Other Crude Oil Production

PART 2
Bitumen and Heavy Oil Upgrading

PART 3
Petroleum Refining

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production

PART 3.1
Surface mining of oil sands and extraction of bitumen

PART 4
Natural Gas Processing

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production

PART 5
Natural Gas Transmission

DIVISION 1
Quantification of Emissions

PART 6
Hydrogen Gas Production

PART 7
Cement and Clinker Production

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production

PART 8
Lime Manufacturing

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production

PART 9
Glass Manufacturing

PART 10
Gypsum Product Manufacturing

PART 11
Mineral Wool Insulation Manufacturing

PART 12
Brick Production

PART 13
Ethanol Production

PART 14
Furnace Black Production

PART 15
2–methylpentamethylenediamine (MPMD) Production

PART 16
Nylon Production

PART 17
Petrochemicals Production

PART 18
Vaccine Production

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production

PART 19
Scrap-based steel production

PART 20
Integrated Steel Production

PART 21
Iron Ore Pelletizing

PART 22
Metal Tube Manufacturing

PART 23
Base Metal Production

PART 24
Potash Production

PART 24.1
Production of Evaporated Salt

PART 25
Coal Mining

PART 26
Production of Metals or Diamonds

PART 27
Char Production

PART 28
Activated Carbon Production

PART 29
Nitrogen-based Fertilizer Production

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production

PART 30
Industrial Potato Processing

PART 31
Industrial Oilseed Processing

PART 32
Alcohol Production

PART 33
Wet Corn Milling

PART 34
Citric Acid Production

PART 35
Sugar Refining

PART 35.1
Production of Malt

PART 36
Pulp and Paper Production

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production

PART 37
Main Assembly of Vehicles

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production

PART 38
Electricity Generation

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production — Main Industrial Activity

DIVISION 3
Secondary Industrial Activity – Quantification of Production

PART 39
Production of wood products

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production

PART 40
Aluminium production from alumina

PART 41
Production of baked anodes — Aluminium

PART 42
Production of calcined petroleum coke — Aluminium

PART 43
Production of alumina from bauxite

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production

PART 44
Production of pneumatic tires

DIVISION 1
Quantification of Emissions

DIVISION 2
Quantification of Production