Output-Based Pricing System Regulations: SOR/2019-266

Canada Gazette, Part II, Volume 153, Number 14

Registration
SOR/2019-266 June 28, 2019

GREENHOUSE GAS POLLUTION PRICING ACT

ENVIRONMENTAL VIOLATIONS ADMINISTRATIVE MONETARY PENALTIES ACT

P.C. 2019-974 June 27, 2019

Her Excellency the Governor General in Council, on the recommendation of the Minister of the Environment, makes the annexed Output-Based Pricing System Regulations pursuant to

(a) sections 192, 193, 198 and 256 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}.

Output-Based Pricing System Regulations

Interpretation

Definition of facility

1 (1) 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 an industrial activity:
- (i) a site, or multiple sites, at which an industrial activity is carried out and the buildings, equipment, and other structures and stationary items located on those sites, and
- (ii) any other sites used in conjunction with the industrial activity, including a quarry, tailings pond, wastewater lagoon or pond and landfill; or
(b) the portion of a natural gas transmission pipeline system within a province, used to transmit processed natural gas, of which the pipelines and associated installations or equipment — including compressor stations, storage installations and compressors — are operated in an integrated way, but excludes pipelines, installations or equipment that are used in the local distribution of natural gas and that are downstream of a metering station.

More than one person responsible — paragraph 1(a)

(2) If more than one person is responsible for the elements referred to in subparagraph (1)(a)(i) or (ii) as an owner or otherwise, including having the charge, management or control of, or as the true decision maker with respect to their operations, those elements are only included in the definition of facility if there is at least one person who is responsible for, owns, has the charge management or control of, or is the true decision maker in common.

More than one person responsible — paragraph 1(b)

(3) If more than one person is responsible for the pipelines and associated installations or equipment referred to in paragraph (1)(b) as an owner or otherwise, including having the charge, management or control of, or as the true decision maker with respect to the pipelines and associated installations or equipment, those pipelines and associated installations or equipment are only included in the definition of facility if there is at least one person who is responsible for, owns, has the charge management or control of, or is the true decision maker in common.

Single facility

(4) 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, if they have more than one person responsible, they have at least one person responsible in common, and are operated in an integrated way, they are deemed to be a single facility.

Interpretation

(5) 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 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 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 an industrial activity is carried out are not included for the purposes of the definition of facility; 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.

Definitions

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

Act means the Greenhouse Gas Pollution Pricing Act. (Loi)
authorized official means
- (a) in respect of a person responsible for a covered facility who is an individual, that individual or another individual who is authorized to act on their behalf;
- (b) in respect of a person responsible for a covered facility that is a corporation, an officer of the corporation who is authorized to act on its behalf; and
- (c) in respect of a person responsible for a covered facility that is another entity, an individual who is authorized to act on its behalf. (agent autorisé)
biomass means plants or plant materials, animal waste or any product made of either of these, including wood and wood products, bio-charcoal, agricultural residues, biologically derived organic matter in municipal and industrial wastes, landfill gas, bio-alcohols, pulping liquor, sludge digestion gas and fuel from animal or plant origin. (biomasse)
boiler unit has the same meaning as subsection 2(1) of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity. (groupe chaudière)
total capacity means, in respect of a unit or equipment that generates electricity, either
- (a) the maximum continuous rating (the maximum net power that can be continuously sustained by a unit or equipment that generates electricity without the use of duct burners, at a temperature of 15˚C and a pressure of 101.325 kPa), expressed in MW of electricity, as most recently reported to a provincial authority of competent jurisdiction or to the electric system operator in the province where the unit or equipment is located, or
- (b) if no report has been made, the most electricity that was generated by the unit or equipment during two continuous hours in a calendar year, expressed in MW of electricity. (capacité totale)
combustion engine means an engine, other than an engine that is self-propelled or designed to be propelled while performing its function, that
- (a) operates according to the Brayton thermodynamic cycle and combusts fossil fuels to produce a net amount of motive power; or
- (b) combusts fossil fuels and uses reciprocating motion to convert thermal energy into mechanical work. (moteur à combustion)
combustion engine unit has the same meaning as subsection 2(1) of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity. (groupe moteur à combustion)
Directive 017 means the directive entitled Directive 017: Measurement Requirements for Oil and Gas Operations, published by the Alberta Energy Regulator on December 13, 2018. (directive 017)
Directive PNG017 means the directive entitled Directive PNG017: Measurement Requirements for Oil and Gas Operations, published by the Government of Saskatchewan on August 1, 2017. (directive PNG017)
dolomitic lime means lime derived from limestone that contains equal to or more than 5% magnesium carbonate. (chaux dolomitique)
electricity generation facility means a covered facility, other than one referred to in paragraph 5(2)(c), that generates electricity as its primary industrial activity, that is used to generate electricity from fossil fuels and that is composed of one unit or a group of units. (installation de production d’électricité)
flaring emissions means controlled emissions of gases from industrial activities as a result of the combustion of a gas or liquid stream produced at a facility, the purpose of which is not to produce useful heat. It does not include emissions from the flaring of landfill gas. (émissions de torchage)
gaseous fuel means a fossil fuel that is gaseous at a temperature of 15°C and a pressure of 101.325kPa. (combustible gazeux)
GHG means greenhouse gas. (version anglaise seulement)
GHGRP means the document entitled Greenhouse Gas Reporting Program, Canada’s Greenhouse Gas Quantification Requirements, published by the Department of the Environment in 2017. (méthode d’ECCC)
global warming potential or GWP means the global warming potential set out in column 2 of Schedule 3 to the Act for the greenhouse gas set out in column 1 of that Schedule. (PRP ou potentiel de réchauffement planétaire)
grey cement means a mix composed primarily of clinker that contains more than 0.5% by weight of ferric oxide, gypsum and limestone. (ciment gris)
HFC means the hydrofluorocarbons set out in items 6 to 24 of Schedule 3 to the Act. (HFC)
high-calcium lime means lime derived from limestone that contains less than 5% magnesium carbonate. (chaux forte en calcium)
industrial process emissions means 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. (émissions liées aux procédés industriels)
industrial product use emissions means emissions from the use of a product in an industrial process that does not involve a chemical or physical reaction and does not react in the process, including emissions from the use of sulphur hexafluoride (SF₆), HFCs and PFCs as cover gases and the use of HFCs and PFCs in a foam-blowing process. (émissions associées à l’utilisation de produits industriels)
IPCC Guidelines means the guidelines entitled 2006 IPCC Guidelines for National Greenhouse Gas Inventories, published by the Institute for Global Environmental Strategies in 2006. (lignes directrices du GIEC)
ISO Standard 14065 means the standard ISO 14065 entitled Greenhouse gases — Requirements for greenhouse gas validation and verification bodies for use in accreditation or other forms of recognition, published by the International Organization for Standardization in 2013. (norme ISO 14065)
leakage emissions means uncontrolled emissions. It does not include industrial process emissions and industrial product use emissions. (émissions dues aux fuites)
liquid fuel means a fossil fuel that is liquid at a temperature of 15°C and a pressure of 101.325kPa. (combustible liquide)
natural gas means a mixture of hydrocarbons — such as methane, ethane or propane — that is in a gaseous state at a temperature of 15°C and a pressure of 101.325 kPa and that is composed of at least 70% methane by volume or that has a higher heating value that is not less than 35 MJ/standard m³ and not more than 41 MJ/standard m³. It excludes landfill gas, digester gas, refinery gas, blast furnace gas, coke oven gas or gas derived through industrial processes from petroleum coke or coal, including synthetic gas. (gaz naturel)
on-site transportation emissions means emissions from registered or unregistered vehicles and other machinery that are used at the facility for the transport of substances, materials, equipment or products used in a production process or for the transport of people, and that are fuelled using fuels delivered in a delivery to which an exemption certificate referred to in subparagraph 36(1)(b)(v) of the Act applies. (émissions liées au transport sur le site)
PFC means the perfluorocarbons set out in in items 25 to 33 of Schedule 3 to the Act. (PFC)
solid fuel means a fossil fuel that is solid at a temperature of 15°C and a pressure of 101.325kPa. (combustible solide)
speciality lime means lime produced by passing dolomitic lime through a kiln more than once or by adding material to dolomitic lime to change its properties. (chaux spécialisée)
specified emission type means an emission type listed in subsection 5(1). (type d’émissions visé)
specified industrial activity means, with respect to a covered facility, an industrial activity specified in paragraph 5(2)(a), subparagraphs 5(2)(b)(i) or (ii), or paragraph 5(c), as the case may be. (activité industrielle visée)
stationary fuel combustion emissions means emissions from stationary devices that combust solid fuels, liquid fuels, gaseous fuels, or tires or asphalt shingles, whether in whole or in part, for the purpose of producing useful heat. (émissions de combustion stationnaire de combustible)
thermal energy means useful thermal energy in the form of steam or hot water that is intended to be used for an industrial purpose. (énergie thermique)
thermal energy to electricity ratio means, in respect of a unit or equipment that generates electricity, the ratio of the total quantity of thermal energy produced to the total quantity of gross electricity generated by the unit or equipment, not including the quantities from the use of duct burners, in a calendar year and expressed in the same units of measurement. (rapport énergie thermique- électricité)
unit means an assembly comprised of a boiler or combustion engine and any other equipment that is physically connected to either, including duct burners and other combustion devices, heat recovery systems, steam turbines, generators and emission control devices, and that generates electricity and, if applicable, produces thermal energy from the combustion of fossil fuels. (groupe)
venting emissions means controlled emissions that occur due to the design of a facility, to procedures used in the manufacture or processing of a substance or product or to pressure exceeding the capacity of the equipment at the facility. (émissions d’évacuation)
waste emissions means emissions that result from waste disposal at a facility, including the landfilling of solid waste, the biological treatment or incineration of waste and the flaring of landfill gas. Waste emissions do not include emissions from the combustion of tires or asphalt shingles, whether in whole or in part, to produce useful heat or on-site transportation emissions. (émissions des déchets)
wastewater emissions means emissions resulting from industrial wastewater and industrial wastewater treatment at a facility. (émissions des eaux usées)
WCI Method means the document entitled Final Essential Requirements of Mandatory Reporting, published on December 17, 2010 by the Western Climate Initiative. (méthode de la WCI)
white cement means a mix composed primarily of clinker that contains 0.5% or less by weight of ferric oxide, gypsum and limestone. (ciment blanc)

Incorporation by reference

(2) Unless otherwise indicated, a reference to any document incorporated by reference into these Regulations, except the ISO Standard 14065 and the GHGRP, is incorporated as amended from time to time.

Purpose

Purpose

3 These Regulations implement an output-based pricing system for industrial GHG emissions with respect to covered facilities where industrial activities are engaged in.

Overview

System components

4 These Regulations set out

(a) the manner in which a person responsible for a covered facility must, under Part 2 of the Act, provide a report that sets out the information with respect to the GHG emissions limit and cause the report to be verified;
(b) the methods to quantify the GHGs from a covered facility and the production from each specified industrial activity engaged in at the covered facility;
(c) the manner of determining the covered facility’s GHG emissions limit based on the facility’s production from each specified industrial activity and the applicable output-based standard; and
(d) the manner in which compensation is provided for excess emissions and surplus credits are issued.

Application

Quantification of GHGs

5 (1) Subject to section 22, GHGs must be quantified for the following emission types:

(a) stationary fuel combustion emissions;
(b) industrial process emissions;
(c) industrial product use emissions;
(d) venting emissions;
(e) flaring emissions;
(f) leakage emissions;
(g) on-site transportation emissions;
(h) waste emissions; and
(i) wastewater emissions.

Specified industrial activities

(2) Output-based standards are established under these Regulations for the following industrial activities:

(a) with respect to a covered facility referred to in paragraph (a) of the definition covered facility in section 169 of the Act, the industrial activities set out in column 1 of Schedule 1 that are engaged in at the facility;
(b) with respect to a covered facility referred to in paragraph (b) of the definition covered facility in section 169 of the Act, that in a request submitted under subsection 172(1) of the Act specified as its primary activity
- (i) an industrial activity set out in column 1 of Schedule 1, the industrial activities set out in column 1 of Schedule 1 that are engaged in at the facility, or
- (ii) an industrial activity other than one set out in column 1 of Schedule 1, the industrial activities – including those set out in column 1 of Schedule 1 – that are engaged in at the facility and that are specified in the notice provided by the Minister that accompanies the covered facility certificate; and
(c) with respect to a covered facility referred to in paragraph (b) of the definition covered facility in section 169 of the Act whose primary activity is something other than an industrial activity, that in a request submitted under subsection 172(1) of the Act specifies an industrial activity, the industrial activities specified in column 1 of Schedule 1 that are engaged in at the facility.

End of designation

Cancellation of designation

6 (1) In accordance with subsection 172(3) of the Act, the Minister may cancel the designation of a covered facility, that was designated on the condition that it would emit at least 10kt of CO₂e in any of the three calendar years following the date of first production, if the covered facility has not met that condition as of December 31 of the third calendar year following that date.

Notice

(2) The Minister must provide notice of their intention to cancel the covered facility’s designation to the person responsible for the covered facility at least 30 days before cancelling the designation.

Ceasing to be a covered facility

7 (1) A facility ceases to be a covered facility under the following circumstances:

(a) it has ceased production from all specified industrial activities for five consecutive compliance periods; or
(b) the person responsible for the covered facility makes a request to that effect because it is expected that the specified industrial activities engaged in at the covered facility will cease for at least 12 consecutive months.

Date of cessation

(2) A covered facility ceases to be a covered facility on the following date:

(a) for the purposes of paragraph (1)(a), on December 31 of the fifth consecutive calendar year for which no production is reported in an annual report; and
(b) for the purposes of paragraph (1)(b), on the later of
- (i) the 30th day following the date the Minister receives the request from the person responsible for the covered facility, or
- (ii) the date the covered facility ceases production.

Cessation of operations during compliance period

(3) In a circumstance in which a facility ceases to be a covered facility before the end of a compliance period, the person who was responsible for that facility must comply with the obligations set out in Division 1 of Part 2 of the Act, including those set out in these Regulations, in respect of the portion of that compliance period during which it was a covered facility.

Covered Facility

Criteria — definition section 169 of Act

8 For the purposes of paragraph (a) of the definition covered facility in section 169 of the Act, the following criteria must be met by a facility that is located in a province or area that is set out in Part 2 of Schedule 1 to the Act:

(a) a report was made, in accordance with a Notice with respect to reporting of greenhouse gases (GHGs) published under section 46 of the Canadian Environmental Protection Act, 1999, in respect of that facility indicating that that facility emitted a quantity of GHGs equal to 50kt or more of CO₂e, as one or more facilities as defined in such a notice, for the 2014 calendar year or any subsequent calendar year; and
(b) the primary activity engaged in at the facility is
- (i) any of the industrial activities set out in column 1 of Schedule 1, in a province or area, other than Saskatchewan, set out in Part 2 of Schedule 1 to the Act, or
- (ii) an industrial activity set out in item 5 or 38, column 1, of Schedule 1, in Saskatchewan.

Compliance Period

Compliance period

9 (1) Subject to subsection (2), a period that begins on January 1 and ends on December 31 for each calendar year, starting in 2019, is specified for the definition compliance period in section 169 of the Act.

Partial 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, for that year begins on

(a) the effective date of registration that is indicated in the Minister of National Revenue’s notice under subsection 64(2) of the Act; or
(b) in the case of a covered facility in Prince Edward Island, the date of registration that is specified in the covered facility certificate issued under subsection 171(2) of the Act.

Person Responsible

Person responsible

10 For the purposes of these Regulations, the person responsible for a facility or a covered facility is the person who owns or is otherwise responsible for the facility or covered facility, including the person who has the charge, management or control of the facility or covered facility, or who is the true decision maker with respect to the operations of the facility or covered facility.

Annual Report

Content of annual report

11 (1) Subject to subsection (2) and section 16, the report that must be submitted by the person responsible for a covered facility for a compliance period under section 173 of the Act is prepared annually for each covered facility for which they are responsible and includes the information listed in Schedule 2 and the following information:

(a) in respect of a covered facility, other than one referred to in paragraph (b) or (c),
- (i) the total quantity of GHGs from the covered facility during the compliance period, expressed in CO₂e tonnes, as determined in accordance with section 17, and
- (ii) the covered facility’s production during the compliance period, from each specified industrial activity, quantified in accordance with section 31;
(b) in respect of an electricity generation facility,
- (i) the total quantity of GHGs from each unit within the covered facility during the compliance period, expressed in CO₂e tonnes, as determined in accordance with section 20,
- (ii) the sum of the total quantities of GHGs determined under subparagraph (i) for all units within the facility, expressed in CO₂e tonnes,
- (iii) the production during the compliance period by each unit within the covered facility from each of the industrial activities set out in paragraphs 38(a) to (c), column 1, of Schedule 1 that are engaged in at the unit, separately for each industrial activity, quantified in accordance with section 32, and
- (iv) the sum of the production from all of the units within the covered facility during the compliance period, from all of the industrial activities set out in paragraphs 38(a) to (c), column 1, of Schedule 1;
(c) in respect of a covered facility, where the specified industrial activities are both the production of coal by mining coal deposits and, if composed of a unit or a group of units that are registered under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, the generation of electricity,
- (i) the total quantity of GHGs from the covered facility during the compliance period, which is the sum of the total quantity of GHGs from the mining of coal deposits, determined in accordance with section 17, and the total quantities of GHGs from the generation of electricity, determined in accordance with section 20, expressed in CO₂e tonnes,
- (ii) with respect to the production of coal by mining coal deposits, the production during the compliance period from each specified industrial activity, in accordance with section 31, and
- (iii) with respect to the generation of electricity,
(d) the quantity of GHGs emitted from the covered facility during the compliance period as determined in accordance with section 35, and, if captured and stored CO₂ is being subtracted under that section, the total quantity of CO₂ captured and stored in a storage project that meets the criteria in subsection 35(2);
(e) the GHG emissions limit applicable to the covered facility for the compliance period, calculated
- (i) in respect of a facility referred to in paragraph (a), in accordance with section 36, 36.1 or 36.2,
- (ii) in respect of a facility referred to in paragraph (b), in accordance with section 41, 41.1 or 41.2, and
- (iii) in respect of a facility referred to in paragraph (c), in accordance with section 42; and
(f) the positive result (corresponding to the quantity of GHGs emitted in excess of the emissions limit) or negative result (corresponding to the difference between the quantity of GHGs emitted and the emissions limit and indicating emissions below the emissions limit) obtained under section 44 for the compliance period, expressed in CO₂e tonnes.

Increased electricity generation capacity

(1.1) For the purposes of subparagraph (1)(a)(ii), if section 36.2 applies with respect to a covered facility, the annual report must include the gross quantity of electricity generated that is attributed the capacity added to the equipment and gross quantity of electricity generated that is attributed to the capacity of the equipment before the additional capacity was added, separately, quantified in accordance with section 31 and subsection 36.2(3).

Increased electricity generation capacity

(1.2) For the purposes of subparagraphs 1(b)(iii) and (iv) and (c)(iii), if section 41.2 applies with respect to an electricity generation facility, the annual report must include,

(a) for each unit whose electricity generation capacity from gaseous fuels was increased by 50 MW or more and that has a thermal energy to electricity ratio of less than 0.9, the gross amount of electricity generated during the compliance period by each unit that is attributed to the capacity added to the unit and the gross amount of electricity generated that is attributed to the capacity of the unit before the additional capacity was added, in accordance with section 32 and subsection 41.2(3), separately; and
(b) the sum, from all of the units referred to in paragraph (a), of the gross amount of electricity generated that is attributed to the capacity added to the units and of the gross amount of electricity generated that is attributed to the capacity of the units before the additional capacity was added, separately.

Exception — new covered facilities

(2) Paragraphs (1)(e) and (f) do not apply with respect to a report that must be submitted by the person responsible for a covered facility for which sections 36 to 42 do not apply under section 43.

Additional content – thermal energy

12 (1) If the person responsible for a covered facility sells thermal energy that is produced at the covered facility to other covered facilities or buys thermal energy from any other covered facility, they must include in their annual report

(a) the quantity of thermal energy, expressed in gigajoules, as well as the thermal energy’s temperature and pressure,
- (i) sold to another covered facility during the compliance period, as determined by the quantity of thermal energy on sales receipts or by another objective method, or
- (ii) bought from another covered facility during the compliance period, as determined by the quantity of thermal energy on sales receipts or by another objective method; and
(b) the ratio of heat from the combustion of fossil fuel to produce that thermal energy, calculated in accordance with section 34.

Additional content – gypsum products

(2) The person responsible for a covered facility where the specified industrial activity set out in item 10, column 1, of Schedule 1 is engaged in, must include in their annual report, the quantity, in tonnes, of each gypsum product that contains at least 70 weight percent of calcium sulphate dihydrate produced during the compliance period.

Additional content – hydrogen gas

(3) If a covered facility where a specified industrial activity set out in items 2, 3, 15 or 29, column 1, of Schedule 1 is engaged in produces hydrogen gas, the person responsible for the covered facility must include in their annual report the quantity of hydrogen gas produced during the compliance period, in tonnes, and the quantity of hydrogen gas sold during the compliance period, in tonnes.

Submission of annual report

13 The person responsible for a covered facility must submit their annual report to the Minister, on or before June 1 of the calendar year following the end of the compliance period for which the annual report is prepared, along with a verification report prepared in accordance with section 52.

Account opening

14 The account that the person responsible for the covered facility opens in accordance with subsection 186(1) of the Act is an Output-Based Pricing System account (OBPS account).

Request for Confidentiality

Content of request

15 A request for confidentiality submitted for the purposes of section 254 of the Act must provide the following information:

(a) the information to which the request pertains, clearly identified;
(b) the reason for the request from among those specified in paragraphs 254(a) to (c) of the Act; and
(c) the supporting justification that the information referred to in paragraph (a) has been treated as confidential by the person making the request and is not, and has never been, available to the public.

Quantification

Variation of General Rules

Production of petrochemical products as a by-product

16 (1) The production of a petrochemical product set out in item 17, column 1, of Schedule 1 as a by-product, at a covered facility where an industrial activity, other than one set out in that item is engaged in, is not an industrial activity covered by item 17, column 1, of Schedule 1.

Additional production of natural gas liquids

(2) If natural gas liquids are produced at a covered facility where a specified industrial activity set out in item 3 or 17, 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 natural gas liquids in accordance with the methods applicable to the industrial activity set out in item 3 or 17, as the case may be, column 1, of Schedule 1; and
(b) for the purposes of sections 31, 36 and 36.2, the industrial activity set out in item 4, column 1, of Schedule 1 is deemed not to be engaged in at the covered facility.

Additional production of hydrogen gas

(3) If hydrogen gas is produced at a covered facility where a specified industrial activity set out in item 2, 3, 15 or 29, 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 hydrogen gas in accordance with the method applicable to the industrial activity set out in item 2, 3, 15 or 29, as the case may be, column 1, of Schedule 1; and
(b) for the purposes of sections 31, 36 and 36.2, the industrial activities set out in items 6 and 17, column 1, of Schedule 1 are deemed not to be engaged in at the covered facility.

Additional production of metal tubes

(4) If metal tubes are produced at a covered facility where a specified industrial activity set out in item 19 or 20, 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 metal tubes in accordance with the method applicable to the industrial activity set out in item 19 or 20, as the case may be, column 1, of Schedule 1; and
(b) for the purposes of sections 31, 36 and 36.2, the industrial activity set out in item 22, column 1, of Schedule 1 is deemed not to be engaged in at the covered facility.

Additional production of lime

(5) If lime is produced at a covered facility where a specified industrial activity set out in item 20, 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 lime in accordance with the method applicable to the industrial activity set out in item 20, column 1, of Schedule 1; and
(b) for the purposes of sections 36 and 36.2, the industrial activity set out in item 8, column 1, of Schedule 1 is deemed not to be engaged in at the covered facility.

Additional production of electricity

(6) If electricity is produced at a covered facility where a specified industrial activity set out in item 20, 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 generation of electricity in accordance with the method applicable to the industrial activity set out in item 20, column 1, of Schedule 1; and
(b) for the purposes of section 36, the industrial activity set out in item 38, column 1, of Schedule 1 is deemed not to be engaged in at the covered facility.

Pyrometallurgical smelting of zinc and lead

(7) If zinc and lead are pyrometallurgically smelted at a covered facility where a specified industrial activity set out in paragraph 23(b), 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 pyrometallurgical smelting of zinc and lead in accordance with the method applicable to the industrial activity set out in paragraph 23(b), column 1, of Schedule 1; and
(b) for the purposes of sections 31, 36 and 36.2, the industrial activity set out in paragraph 23(c), column 1, of Schedule 1 is deemed not to be engaged in at the covered facility.

Additional production of precious metals

(8) If gold, silver, platinum or palladium is produced at a covered facility where a specified industrial activity set out in paragraph 26(d), 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 those metals in accordance with the method applicable to the industrial activity set out in paragraph 26(d), column 1, of Schedule 1; and
(b) for the purposes of sections 31, 36 and 36.2, the industrial activity set out in paragraph 26(c) or (f), column 1, of Schedule 1 is deemed not to be engaged in at the covered facility.

Additional production of petrochemicals

(9) 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 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 that petrochemical in accordance with the method applicable to the industrial activity set out in item 3 or 4, as the case may be, column 1, of Schedule 1; and
(b) for the purposes of sections 31, 36 and 36.2, the industrial activity set out in item 17, column 1, of Schedule 1 is deemed not to be engaged in at the covered facility.

Additional production of precious metals

(10) If silver, platinum or palladium is produced at a covered facility where a specified industrial activity set out in paragraph 26(f), 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 those metals in accordance with the method applicable to the industrial activity set out in paragraph 26(f), column 1, of Schedule 1; and
(b) for the purposes of sections 31, 36 and 36.2, the industrial activity set out in paragraph 26(c), column 1, of Schedule 1 is deemed not to be engaged in at the covered facility.

Quantification of GHGs

Total GHGs

17 (1) Subject to subsection (5) and section 18, the total quantity of GHGs from a covered facility other than an electricity generation facility, during a compliance period, expressed in CO₂e tonnes, is determined by the formula

where
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) or section 19;
GWP_j is the global warming potential of the GHG type “j”;
i is the i^th specified emission type, where “i” goes from 1 to n and where n is the number of the facility’s specified emission types; and
j is the j^th GHG type, where “j” goes from 1 to m and where m is the number of greenhouse gases.

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:

(a) in the case of a GHG from industrial activities set out in items 1 to 37, column 1, of Schedule 1 and also set out in column 2 of the table to the Part of Schedule 3 that is applicable to those industrial activities, from a specified emission type set out in column 1 of that table, the quantities of that GHG calculated in accordance with the requirements of the methods set out in column 3 of that table for that emission type and GHG;
(b) in the case of a 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 from a specified emission type not set out in column 1, the quantities of that GHG calculated in accordance with
- (i) the GHGRP or the WCI Method, if those methods are applicable to the facility’s industrial activities, or
- (ii) the IPCC Guidelines, if the methods referred to in subparagraph (i) are not applicable; and
(c) in the case of a GHG from industrial activities not set out in column 1 of Schedule 1, the quantities of that GHG calculated in accordance with
- (i) the GHGRP or the WCI Method, if those methods are applicable to the facility’s industrial activities, or
- (ii) the IPCC Guidelines, if the methods referred to in subparagraph (i) are not applicable.

Sampling, analysis and measurement requirements

(3) The sampling, analysis and measurement requirements that apply are

(a) if a GHG is quantified in accordance with paragraph 2(a), the requirements set out in column 4 of the table to the applicable Part of Schedule 3 for the specified emission type set out in column 1 and the GHG set out in column 2; or
(b) if a GHG is quantified in accordance with paragraph 2(b) or (c), the requirements specified in the methods or guidelines used for the purposes of those paragraphs.

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 facility are missing for a given period of a compliance period, replacement data for the given period must be calculated in accordance with

(a) if a GHG is quantified in accordance with paragraph 2(a), the requirements set out in column 5 of the table to the applicable Part of Schedule 3 for the specified emission type in column 1 and the GHG set out in column 2; or
(b) if a GHG is quantified in accordance with paragraph 2(b) or (c), the requirements specified in the methods or guidelines used for the purposes of those paragraphs.

Biomass — exclusion of CH₄ and N₂O

(5) For the purposes of the determination made under subsection (1), the quantities of CH₄ and N₂O generated from stationary devices that combust biomass for the purpose of producing useful heat are subtracted from the quantities of CH₄ and N₂O calculated in accordance with subsections (2) to (4) for stationary fuel combustion emissions.

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 covered facilities referred to in paragraphs 5(2)(c) and 11(1)(c) — are calculated in accordance with the methods that are applicable to any of the industrial activities engaged in at the covered facility.

Covered facility referred to in paragraph 5(2)(c)

19 The quantities of the GHGs for specified emission types from a covered facility referred to in paragraph 5(2)(c) are calculated in accordance with

(a) the GHGRP or the WCI Method, if those methods are applicable; or
(b) the IPCC Guidelines, if the methods referred to in paragraph (a) are not applicable.

Total emissions per unit — electricity

20 (1) Subject to subsection (6), with respect to an electricity generation facility, the total quantity of GHGs from each unit within a facility, during a compliance period, expressed in CO₂e tonnes, is determined by the formula

where
E_j is the quantity of each GHG type “j” from the unit during a compliance period for each specified emission type determined in accordance with subsections (2) to (5);
GWP_j is the global warming potential of the GHG type “j”;
i is the i^th specified emission type, where “i” goes from 1 to n and where n is the unit’s number of specified emission types;
j is the j^th GHG type, where “j” goes from 1 to m and where m is the number of greenhouse gases.

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

(a) for CO₂, CH₄ and N₂O from stationary fuel combustion emissions, the quantity of each of those GHGs calculated in accordance with section 1 of Part 38 of Schedule 3 for each unit;
(b) for a GHG set out in column 2 of the table to Part 38 of Schedule 3 for a specified emission type set out in column 1, the quantities of that GHG calculated in accordance the requirements of the methods set out in column 3 of that table for that emission type; and
(c) for a GHG not referred to in paragraph (a) or (b), the quantity of that GHG calculated in accordance with
- (i) the GHGRP or the WCI Method, if those methods are applicable, or
- (ii) the IPCC Guidelines, if the methods referred to in subparagraph (i) are not applicable.

Apportioning GHGs

(3) For the purposes of paragraph (2)(b) or (c), if the GHGs for a specified emission type referred to in subsection (2) can only be quantified for the facility as a whole, the quantity of those GHGs must be apportioned to the facility’s units on the basis of each unit’s total generation of electricity relative to the facility’s total generation of electricity.

Sampling, analysis and measurement requirements

(4) The sampling, analysis and measurement requirements that apply are

(a) for a GHG quantified in accordance with paragraph (2)(a), the requirements referred to in section 2 of Part 38 of Schedule 3 for each of the units;
(b) for a GHG quantified in accordance with paragraph (2)(b), the requirements set out in column 4 of the table to Part 38 of Schedule 3 for the specified emission type set out in column 1; and
(c) for a GHG quantified in accordance with paragraph (2)(c), the requirements set out in the methods or guidelines used for the purpose of that paragraph.

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 from a unit are missing for a given period of a compliance period, replacement data for the given period must be calculated in accordance with

(a) if a GHG is quantified in accordance with paragraph (2)(a), the requirements set out in section 3 of Part 38 of Schedule 3;
(b) if the GHG is quantified in accordance with paragraph (2)(b), the requirements set out in column 5 of the table to Part 38 of Schedule 3 for the specified emission type set out in column 1; and
(c) if the GHGs are quantified in accordance with paragraph (2)(c), the requirements set out in the methods or guidelines used for the purpose of that paragraph.

Biomass — exclusion of CH₄ and N₂O

(6) For the purposes of the determination made under subsection (1), the quantity of CH₄ and N₂O generated from stationary devices that combust biomass for the purpose of producing useful heat are subtracted from the quantity of CH₄ and N₂O calculated in accordance with subsections (2) to (5) for stationary fuel combustion emissions.

Hybrid configuration

21 For the purposes of section 20, if a combustion engine unit and a boiler unit share the same steam turbine, the GHGs from those units are quantified as follows:

(a) with respect to a combustion engine unit, the quantification provisions apply to the assembly comprised of combustion engines and any other equipment connected to them, including the steam turbine that it shares with the boiler unit; and
(b) with respect to a boiler unit, the quantification provisions apply to the assembly comprised of boilers and any other equipment connected to them, including the steam turbine that it shares with the combustion engine unit.

Biomass — exclusion of CO₂

22 (1) CO₂ from biomass is not included in the quantity of CO₂ calculated in accordance with subsections 17(2) to (4) or 20(2) to (5).

Methane

(2) CH₄ from venting or leakage emissions from an industrial activity set out in item 1, 2, 4 or 5, column 1, of Schedule 1 is not included in the quantity of CH₄ calculated in accordance with subsections 17(2) to (4).

De minimis

23 (1) Subject to subsection (2), the quantity of a GHG for any specified emission type does not need to be included in the determination made under subsections 17(2) to (4) or 20(2) to (5) if the quantity of the GHG, expressed in CO₂e tonnes, does not exceed 0.5% of the total quantity of GHGs determined under subsection 17(1) or 20(1).

Limit

(2) The sum of the quantities of GHGs not included under subsection (1) cannot exceed 0.5% of the total quantity of GHGs determined under subsection 17(1) or 20(1).

Rounding

24 Any result from a calculation under subsections 17(1) and 20(1) is to be rounded to the nearest whole number and, if the number is equidistant between two whole consecutive numbers, to the higher number.

Continuous Emissions Monitoring System

25 For the purposes of the GHGRP, if a CEMS is used to quantify GHGs, the person responsible for the covered facility must ensure that the system complies with the requirements of the Reference Method for Source Testing: Quantification of Carbon Dioxide Releases by Continuous Emission Monitoring Systems from Thermal Power Generation, published by the Department of the Environment in June 2012.

Permit To Use an Alternative Method

Alternative method

26 Despite sections 17 and 20, the person responsible for a covered facility may use a method other than a method or guideline required under those sections if they have a permit issued in accordance with section 28.

Application for permit

27 (1) An application for a permit must be submitted to the Minister and must contain the information referred to in Schedule 4.

Certification

(2) The application must be accompanied by a certification, dated and signed by the person responsible for the covered facility or by their authorized official, stating that the information contained in the application is accurate and complete.

Conditions of issuance

28 (1) The Minister must issue the permit to use a quantification method other than one prescribed in these Regulations 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 prescribed method or guideline;
(b) the person responsible for the covered facility demonstrates that the quantification method being proposed is at least as rigorous as the prescribed method or guideline and provides equivalent results to those that would have been obtained from the prescribed method or guideline;
(c) the person responsible for the covered facility provides a plan describing measures that will be taken to enable the use of the prescribed method or guideline and the implementation period for that plan, up to a maximum of two years; and
(d) the requested term of the permit does not exceed the period for which the permit is necessary.

Period of validity

(2) The term of the permit must not exceed 24 months.

Grounds for refusing permit

(3) The Minister must refuse to issue a permit if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in support of their application.

Renewal

(4) The permit can only be renewed once.

Application for renewal

29 (1) The application for the renewal of a permit must include the information referred to in Schedule 4 and an explanation of the reasons why the plan that was submitted in the initial permit application was not implemented within the period identified in the initial application. The application for renewal must be submitted to the Minister at least 90 days before the expiration of the permit.

Conditions for renewal

(2) The Minister must renew the permit if the conditions set out in subsection 28(1) are met.

Grounds for revocation

30 (1) The Minister must revoke the permit if the Minister has reasonable grounds to believe that the permit holder has provided false or misleading information.

Notice of revocation

(2) Before revoking a permit, the Minister must provide the permit holder with

(a) written reasons for the revocation; and
(b) an opportunity to make written representations in respect of the revocation.

Date of revocation

(3) The revocation of a permit is effective 30 days after the day on which the Minister notifies the permit holder.

Quantification of Production for Specified Industrial Activities

General rule

31 (1) Subject to subsection (4) and section 16, the production from a covered facility, other than an electricity generation facility, from each specified industrial activity during a compliance period is quantified

(a) in the case of production from a specified industrial activity set out in items 1 to 37, 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;
(b) in the case of production from a specified industrial activity set out in paragraphs 38(a) to (c), column 1, of Schedule 1, the production is
- (i) quantified in whole for the compliance period in accordance with the requirements set out in sections 6 and 7 of Part 38 of Schedule 3, or
- (ii) not quantified, in whole or in part, for the compliance period; and
(c) in the case of production from a specified industrial activity not set out in column 1 of Schedule 1, in the units of measurement provided in the request under subsection 172(1) of the Act.

Measuring device

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

(a) installed, operated, maintained and calibrated in accordance with the manufacturer’s specifications or any applicable generally recognized national or international industry standard; and
(b) maintained to be accurate within ± 5%.

Engineering estimates or mass balance

(3) If it is not possible to directly measure production using a measuring device, it may be quantified using engineering estimates or mass balance.

Transitional provision

(4) For the 2019 calendar year

(a) the production quantified in accordance with paragraphs (1)(a) and (c), must be accurate within ± 5%; and
(b) the production referred to in paragraph (1)(b) may be quantified by the person responsible for the regulated facility in accordance with subsection 9(2) and section 103 of the Greenhouse Gas Emissions Information Production Order, as it read before August 1, 2019.

Electricity generation facility

32 (1) Subject to subsection (2), the gross electricity generated during a compliance period by each unit within the electricity generation facility, from each of the industrial activities set out in paragraphs 38(a) to (c), column 1, of Schedule 1 that is engaged in at the unit, is determined as follows:

(a) if a unit uses only one fossil fuel to generate electricity, in accordance with subsection 4(1) and section 5 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 4(2) and (3) and section 5 of Part 38 of Schedule 3.

Choose not to quantify

(2) The person responsible for the electricity generation facility may choose not to quantify part or all of the quantity of electricity generated from one unit or a group of units.

Rounding

33 Any result from a calculation under subsection 31(1) or section 32 is rounded to three significant figures.

Ratio of Heat

Ratio of heat

34 (1) The ratio of heat from the combustion of fossil fuels during a compliance period is

(a) equal to 1 when the thermal energy is produced from the combustion of only fossil fuels;
(b) for a covered facility not specified in paragraph (c), 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
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 7(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 during the compliance period for the generation of thermal energy in accordance with sections 2.C.1 and 2.C.3 of the GHGRP, 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 7(2) of Part 38 of Schedule 3 and the WCI Method WCI.214,
HHV_k is the higher heating value for biomass fuel type “k” combusted in the facility during the compliance period for the generation of thermal energy in accordance with sections 2.C.1 and 2.C.3 of the GHGRP and the WCI Method WCI.214, 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
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(3) of Part 38 of Schedule 3,
HHV_i is the higher heating value of the fossil fuel of type “i” combusted in the facility during the compliance period for the generation of thermal energy determined in accordance with subsection 24(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, 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 4(3) of Part 38 of Schedule 3,
HHV_k is the higher heating value for biomass fuel type “k” combusted in the facility during the compliance period for the generation of thermal energy determined in accordance with subsection 24(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, 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.

Default ratio of heat

(2) Despite paragraph (1)(b) or (c), if, for any reason beyond the control of the person responsible for a covered facility, the data required to quantify the ratio of heat from the combustion of fossil fuels are missing for a given period during the 2019 calendar year, 1 can be used as the ratio of heat from the combustion of fossil fuels.

Emission of GHGs

Calculation

35 (1) The person responsible for a covered facility must determine the quantity of GHGs that are emitted from the covered facility during a compliance period in accordance with the formula

A – B

where
A is the total quantity of GHGs from the covered facility, expressed in CO₂e tonnes, during the compliance period,
- (a) in the case of a facility referred to in paragraph 11(1)(a), determined in accordance with section 17,
- (b) in the case of a facility referred to in paragraph 11(1)(b), corresponding to the sum referred to in subparagraph 11(1)(b)(ii), and
- (c) in the case of a facility referred to in paragraph 11(1)(c), corresponding to the sum referred to in subparagraph 11(1)(c)(i); and
B is the quantity of CO₂ captured at the covered facility that is stored during the compliance period in a storage project, determined using the quantification method described in section 1 of the GHGRP, expressed in CO₂e tonnes.

Storage requirements

(2) For the purposes of the description of B in subsection (1), the quantity of CO₂ may only be included if it has been permanently stored in a storage project that meets the following criteria:

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

Biomass

(3) The quantity of CO₂ from biomass is not included in the amount determined for B in subsection (1).

Deemed emission of CO₂

(4) For greater certainty, the quantity of CO₂ from a covered facility that has been captured but has not been permanently stored in a storage project that meets the requirements of subsection (2) is deemed to have been emitted by the covered facility and is included in the quantity of GHGs that are emitted from the covered facility.

Emissions Limit

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, that standard,
- (b) for a specified industrial activity set out in column 1 of Schedule 1 and for which column 3 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, or
- (c) for any specified industrial activity not set out in column 1 of Schedule 1, the output based standard calculated in accordance with section 37; and
i is the i^th specified industrial activity where “i” goes from 1 to n where n is the total number of specified industrial activities engaged in at the covered facility.

Ethanol production

(2) For the purposes of subsection (1), the person responsible for a covered facility must not include the specified industrial activity set out in paragraph 13(b), column 1, of Schedule 1 unless the covered facility also includes the specified industrial activity set out in paragraph 13(a), column 1. The covered facility is deemed to not be engaged in the specified industrial activity set out in item 32, column 1, of that Schedule.

Oilseeds

(3) For the purposes of subsection (1), the person responsible for a covered facility where the specified industrial activity set out in item 31, column 1, of Schedule 1 is engaged in may, for the 2019 calendar year, quantify their production in finished oilseed products and use an output-based standard of 0.0431 CO₂e tonnes per unit of measurement of production, instead of the production metric set out in column 2 and the output-based standard set out in column 3.

Greater certainty — fertilizer

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

Output-based standard

(5) For the purposes of subsection (1), if an output-based standard must be calculated, it is calculated once, except in the situation referred to in subsection 39.

New electricity production — gaseous fuel

36.1 (1) Despite subsection 36(1), if a covered facility — other than one referred to in subsection 16(6) — begins generating electricity on or after January 1, 2021 and meets the following criteria, the person responsible for the covered facility must apply, for the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, the applicable output-based standard, in accordance with subsection (2), for each compliance period, as of the compliance period during which the covered facility began generating electricity:

(a) the electricity is generated from gaseous fuel by equipment that is designed to operate at a thermal energy to electricity ratio of less than 0.9; and
(b) the covered facility has an electricity generation capacity equal to or greater than 50 MW from that equipment.

Decreasing output-based standard

(2) The output-based standard that applies to the industrial activity referred to in paragraph 38(c), column 1, of Schedule 1 is, as the case may be

(a) 370 CO₂e tonnes per unit of measurement, for the 2021 compliance period,
(b) 329 CO₂e tonnes per unit of measurement, for the 2022 compliance period,
(c) 288 CO₂e tonnes per unit of measurement, for the 2023 compliance period,
(d) 247 CO₂e tonnes per unit of measurement, for the 2024 compliance period,
(e) 206 CO₂e tonnes per unit of measurement, for the 2025 compliance period,
(f) 164 CO₂e tonnes per unit of measurement, for the 2026 compliance period,
(g) 123 CO₂e tonnes per unit of measurement, for the 2027 compliance period,
(h) 82 CO₂e tonnes per unit of measurement, for the 2028 compliance period,
(i) 41 CO₂e tonnes per unit of measurement, for the 2029 compliance period, and
(j) 0 CO₂e tonnes per unit of measurement, for the 2030 compliance period and subsequent compliance periods.

Increased capacity of electricity generation

36.2 (1) Subject to subsections 16(1) to (5) and (7) to (10), if, on or after January 1, 2021, a covered facility — other than a covered facility referred to in subsection 16(6) — increases its electricity generation capacity from gaseous fuels by 50 MW or more and that increased capacity is from equipment that has a thermal energy to electricity ratio of less than 0.9 and that was added after that date or has had its capacity increased and, the person responsible for the covered facility must determine the covered facility’s GHG emissions limit for each compliance period, as of the compliance period during which the increase occurred, in accordance with subsection (2).

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 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, except from equipment referred to in the descriptions C, E and F;
B_i is the 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, that standard,
- (b) for a specified industrial activity set out in column 1 of Schedule 1 and for which column 3 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, or
- (c) for any specified industrial activity not set out in column 1 of Schedule 1, the output based standard calculated in accordance with section 37; and
C 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, 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;
D is the output-based standard set out in subsection 36.1(2) that is applicable to the compliance period in question;
E is, for equipment with increased electricity generation capacity and has a thermal energy to electricity ratio of less than 0.9, other than equipment referred to in the description of C, 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);
F is, for equipment with increased electricity generation capacity and has a thermal energy to electricity ratio of less than 0.9, other than equipment referred to in the description of C, 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); and
G is the output-based standard set out in column 3 of part 38 of Schedule 1, that is applicable to the specified industrial activity set out in paragraph 38(c), column 1; and
i is the i^th specified industrial activity where “i” goes from 1 to n where n is the total number of the covered facility’s specified industrial activities.

Apportionment of electricity generation

(3) For the purposes of the descriptions of E and F 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.

Increased capacity — rule

(4) For the purposes of subsection (1), the electricity generation capacity of a facility increases by 50 MW or more for a calendar year as of the day on which its electricity generation capacity is 50 MW greater than its electricity generation capacity on December 31, 2020. For greater certainty, any increase in capacity is cumulative.

Presumption

36.3 If the output-based standard set out in subsection 36.1(2) applies to a covered facility’s generation of electricity for a given compliance period, it continues to apply for all subsequent compliance periods even if

(a) for the purposes of section 36.1, the covered facility is not generating electricity from gaseous fuel or the equipment in question has a thermal energy to electricity ratio that is equal to or greater than 0.9; or
(b) for the purposes of section 36.2, the equipment in question is not generating electricity from gaseous fuel or has a thermal energy to electricity ratio that is equal to or greater than 0.9.

Calculated output-based standard

37 (1) Subject to subsection (3) and sections 38 to 40, 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 is determined by the formula

where
A is the total quantity of GHGs from the covered facility for reference year “i”, determined in accordance with section 17, 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”, determined by the quantity of thermal energy on sales receipts or by another objective method, expressed in gigajoules,
N is the quantity of thermal energy that was bought from another covered facility in reference year “i”, as determined 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 for reference year “i” and is
- (a) if M is greater than N, the ratio of heat determined under section 34 for reference year “i” for the covered facility, or
- (b) 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, or
- (b) 0 for all reference years if 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 obtained by dividing the result of the following formula by the number of reference years:

0.015 × A

C 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, for each of those activities;
D is the production from a covered facility from the 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 paragraphs 7(c), 8(b) and (c), and 20(d), column 1, of Schedule 1,
- (b) 90% for a specified industrial activity set out in item 22 and paragraphs 23(a) and 29(d), column 1, of Schedule 1, and
- (c) 80% for all other specified industrial activities; 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).

Reference years

(2) The reference years applicable to the specified industrial activities set out in column 1 of Schedule 1 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), at the choice of the responsible person, either,
- (i) the 2017 and 2018 calendar years, or
- (ii) the compliance period; or
(b) for a covered facility for which an emissions limit is being calculated for the first time but for which the person responsible has submitted an annual report under these Regulations for a previous compliance period without including the information referred to in paragraphs 11(1)(e) and (f) in accordance with subsection 11(2), either
- (i) the two calendar years preceding the compliance period for which the emissions limit is calculated, if the data are available for those years,
- (ii) the calendar year preceding the compliance period for which the emissions limit is calculated, if the data are not available for the two calendar years referred to in (i), or
- (iii) the compliance period for which the emissions limit is being calculated, if that data are not available for those preceding calendar years.

Thermal energy allocation

(3) For the purposes of subsection (1), if an output-based standard must be calculated with respect to a covered facility for more than one specified industrial activity, the allocation for net thermal energy can only be deducted from one of those calculations.

Rounding

(4) The result from the calculation under subsection (1) is rounded to three significant figures.

Exception — steel

38 (1) For the purposes of the description of C in subsection 37(1), if the specified industrial activity for which the output-based standard is being calculated is the industrial activity set out in paragraph 20(d), column 1, of Schedule 1 and the covered facility is also engaged in the generation of electricity, the quantity of GHGs from the generation of electricity attributable to the industrial activity set out in that item are not included in the total quantity of GHGs determined for C.

For greater certainty

(2) For greater certainty, the quantity of GHGs from the generation of electricity attributable to the specified industrial activities set out in paragraphs 20(a) to (c), column 1, of Schedule 1 are included in the total quantity of emissions determined for C.

Recalculation of output-based standard

39 If an output-based standard applicable to a specified industrial activity set out in column 1 of Schedule 1 was calculated for a compliance period that started after January 1 of a given year, it must be recalculated in accordance with subsection 37(1) for the next compliance period.

Covered facility — subparagraph 5(2)(b)(ii)

40 Despite section 37, for a specified industrial activity set out in subparagraph 5(2)(b)(ii), other than a specified industrial activity set out in column 1 of Schedule 1, the information provided in the request under subsection 172(1) of the Act is used for the calculation of the output-based standard under subsection 37(1).

Electricity

41 (1) Subject to subsection (2) and sections 41.1 and 41.2, the person responsible for an electricity generation facility must determine the GHG emissions limit that applies to the electricity generation facility for each compliance period, expressed in CO₂e tonnes, in accordance with the formula

where
A_j is the gross amount of electricity generated during the compliance period quantified in accordance with section 32, for each unit “i” within the electricity generation facility, from each of the industrial activities set out in paragraphs 38(a) to (c), column 1, of Schedule 1 that is engaged in at the electricity generation facility;
B_j is the output-based standard applicable to each specified industrial activity set out in paragraphs 38(a) to (c), column 1, of Schedule 1 that are engaged in at each unit “i” and that is set out in column 3;
i is the i^th unit, where “i” goes from 1 to n and where n is the total number of units within the electricity generation facility generating electricity using fossil fuels; and
j is the j^th activity, where “j” goes from 1 to m and where m is the total number of industrial activities set out in paragraphs 38(a) to (c), column 1, of Schedule 1 that are engaged in at the facility.

Output-based standard — exception

(2) The output-based standard applicable to the industrial activity set out in paragraph 38(a), column 1, of Schedule 1 applies to a unit if it generates electricity using liquid or gaseous fuel and it

(a) is registered under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations; and
(b) used solid fuel to generate electricity in 2018.

New electricity production facility — gaseous fuel

41.1 (1) If an electricity generation facility begins generating electricity on or after January 1, 2021 and meets the following criteria, the person responsible for the covered facility must determine the GHG emissions limit that applies to the facility for each compliance period as of the compliance period during which the electricity generation began, in accordance with subsection (2):

(a) at least one unit within the facility generates electricity from gaseous fuels; and
(b) at least one of the units that generates electricity from gaseous fuels within the facility has an electricity generation capacity equal to or greater than 50 MW and is designed to operate at a thermal energy to electricity ratio of less than 0.9.

Different output-based standard

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

where
A_j is, for each unit “i” within the electricity generation facility that generates electricity from solid fuel or liquid fuel, the gross amount of electricity generated during the compliance period, quantified in accordance with section 32, from the specified industrial activities set out in paragraph 38(a) and (b), column 1, of Schedule 1 that are engaged in at the unit;
B_j the output-based standard applicable to each specified industrial activity set out in paragraphs 38(a) and (b), column 1, of Schedule 1 that the are engaged in at each unit “i” and that is set out in column 3;

C is, for each unit “k” within the electricity generation facility that generates electricity from gaseous fuels, that has an electricity generation capacity equal to or greater than 50 MW and that has a thermal energy to electricity ratio of less than 0.9, the gross amount of electricity generated during the compliance period in accordance with section 32, from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1 that is engaged in at the unit;
D is the output-based standard applicable and is
- (a) 370 CO₂e tonnes per unit of measurement, for compliance period 2021,
- (b) 329 CO₂e tonnes per unit of measurement, for compliance period 2022,
- (c) 288 CO₂e tonnes per unit of measurement, for compliance period 2023,
- (d) 247 CO₂e tonnes per unit of measurement, for compliance period 2024,
- (e) 206 CO₂e tonnes per unit of measurement, for compliance period 2025,
- (f) 164 CO₂e tonnes per unit of measurement, for compliance period 2026,
- (g) 123 CO₂e tonnes per unit of measurement, for compliance period 2027,
- (h) 82 CO₂e tonnes per unit of measurement, for compliance period 2028,
- (i) 41 CO₂e tonnes per unit of measurement, for compliance period 2029, and
- (j) 0 CO₂e tonnes per unit of measurement, for compliance period 2030 and subsequent compliance periods; and
E is, for each unit “l” within the electricity generation facility that generate electricity from gaseous fuels, has an electricity generation capacity of less than 50 MW or a thermal energy to electricity ratio of 0.9 or greater, the gross amount of electricity generated during the compliance period from the specified industrial activity engaged in at the unit set out in paragraph 38(c), column 1, of Schedule 1, quantified in accordance with section 32;
F the output-based standard applicable to each specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1 that are engaged in at each unit “i” and that is set out in column 3;
i is the i^th unit, where “i” goes from 1 to n and where n is the total number of units within the electricity generation facility generating electricity using solid fuel or liquid fuel;
j is the j^th activity, where “j” goes from 1 to m and where m is the total number of industrial activities set out in paragraphs 38(a) to (b), column 1, of Schedule 1 that is engaged in at the electricity generation facility;
k is the k^th unit, where “k” goes from 1 to r and where r is the total number of units within the electricity generation facility, generating electricity using gaseous fuel, that have an electricity generation capacity equal to or greater than 50 MW and a thermal energy to electricity ratio of less than 0.9;
l is the l^th unit, where “l” goes from 1 to s and where s is the total number of units within the electricity generation facility, generating electricity using gaseous fuel, that have an electricity generation capacity of less than 50 MW or a thermal energy to electricity ratio of 0.9 or greater.

Increased capacity of electricity generation

41.2 (1) If, on or after January 1, 2021, an electricity generation facility’s electricity generation capacity from gaseous fuels increases by 50 MW or more and that increased capacity is from a unit designed to operate at a thermal energy to electricity ratio of less than 0.9, the person responsible for the covered facility must determine the GHG emissions limit that applies to the facility for each compliance period, as of the compliance period during which the increase occurred, in accordance with subsection (2).

Different output-based standard

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

Detailed information can be found in the surrounding text.

where

A_j is the gross amount of electricity generated during the compliance period, quantified in accordance with section 32, for each of the following units:
- (a) for each unit “i” within the electricity generation facility, from each of the specified industrial activities set out in paragraphs 38(a) and (b), column 1, of Schedule 1 that are engaged in at the electricity generation facility,
- (b) from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1 that is engaged in at the unit, for each unit “i” within an electricity generation facility that
  - (i) was generating electricity prior to the facility’s increase in electricity generation capacity, except units referred to in the description of E or F, and
  - (ii) that began generating electricity on or after January 1, 2021, if the unit has an electricity generation capacity of less than 50 MW or designed to operate at a thermal energy to electricity ratio equal to or greater than 0.9;
B_j the output-based standard applicable to each of the specified industrial activities set out in paragraphs 38(a) to (c), column 1, of Schedule 1 that are engaged in at each unit “i” and that is set out in column 3;
C is, for each unit “k” within the electricity generation facility that started generating electricity from gaseous fuels on or after January 1, 2021, that has an electricity generation capacity equal to or greater than 50 MW and that has a thermal energy to electricity ratio of less than 0.9, the gross amount of electricity generated during the compliance period quantified in accordance with section 32, from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1 that is engaged in at the electricity generation facility;
D is the output-based standard set out in the description of D in subsection 41.1(2) that is applicable to the compliance period in question;
E is, for each unit “l” that generated electricity from gaseous fuels within the electricity generation facility prior to the facility’s increase in electricity generation capacity and whose electricity generation capacity was increased by 50 MW or more and whose thermal energy to electricity ratio of less than 0.9, the gross amount of electricity generated during the compliance period that is attributed to the capacity added to a unit, from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, quantified in accordance with section 32 and subsection (3);
F is, for each unit “l” that generated electricity from gaseous fuels within the electricity generation facility prior to the facility’s increase in electricity generation capacity and whose electricity generation capacity was increased by 50 MW or more and whose thermal energy to electricity ratio of less than 0.9, the gross amount of electricity generated during the compliance period that is attributed to the capacity of the unit 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 32 and subsection (3);
G is the output-based standard applicable to the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1 and set out in column 3;
i is the i^th unit, where “i” goes from 1 to n and where n is the total number of units within the electricity generation facility generating electricity using fossil fuels, except units referred to in the description of k and l;
j is the j^th activity, where “j” goes from 1 to m and where m is the total number of industrial activities set out in paragraphs 38(a) to (c), column 1, of Schedule 1 that are engaged in at the electricity generation facility;
k is the k^th unit, where “i” goes from 1 to r and where r is the total number of units within the electricity generation facility that started generating electricity from gaseous fuels on or after January 1, 2021, that have an electricity generation capacity equal to or greater than 50 MW and that have a thermal energy to electricity ratio of less than 0.9; and
l is the l^th unit, where “i” goes from 1 to s and where s is the total number of units that generated electricity from gaseous fuels within the electricity generation facility prior to the facility’s increase in electricity generation capacity and whose electricity generation capacity was increased by 50 MW or more and whose thermal energy to electricity ratio of less than 0.9.

Apportionment of electricity generation

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

Increased capacity — rule

(4) For the purposes of subsection (1), the electricity generation capacity, from gaseous fuels, of an electricity generation facility increases by 50 MW or more for a calendar year as of the day on which its electricity generation capacity is 50 MW greater than its electricity generation capacity on December 31, 2020. For greater certainty, any increase in a unit’s capacity is cumulative.

Presumption

41.3 For the purposes of sections 41.1 and 41.2, if the output-based standard set out in subsection 41.1(2) applies to a unit or group of units for a compliance period for the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, that output-based standard will continue to apply to the unit or group of units even if the unit or group of units is not producing electricity from gaseous fuel or has a thermal energy to electricity ratio that is equal to or greater than 0.9.

Coal and electricity

42 The person responsible for a covered facility where the specified industrial activities engaged in are both the production of coal by mining coal deposits and the generation of electricity and that is comprised of a unit or a group of units that are registered under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations must calculate the GHG emissions limit that applies to the covered facility for each compliance period by adding the emissions limit obtained in subsection 36(1) for that compliance period for the specified industrial activity set out in item 25, column 1, of Schedule 1 and the emissions limit determined under section 41 or 41.2 for that compliance period for the specified industrial activities set out in paragraphs 38(a) to (c), column 1, of that Schedule, expressed in CO₂e tonnes.

New covered facilities

43 (1) If, on January 1 of a compliance period, a covered facility has not completed two calendar years of production following the date of first production, sections 36 to 42 do not apply to the covered facility for that compliance period.

Primary activity

(2) Subsection (1) only applies to a covered facility whose primary activity is a specified industrial activity.

New electricity generation facility

(3) Subsection (1) does not apply to an electricity generation facility that begins generating electricity on or after January 1, 2021.

Date of production

(4) For the purposes of subsection (1), to determine the date of first production for a covered facility all industrial activities that the facility has previously been or is currently engaged in must be taken into account.

Assessment

Assessment of emissions against emissions limit

44 (1) The person responsible for a covered facility must assess for each compliance period the quantity of GHGs that are emitted from the covered facility during the applicable compliance period against its applicable GHG emissions limit in accordance with the formula

A − B

where

A is the quantity of GHGs that are emitted from the covered facility during the compliance period, expressed in CO₂e tonnes, determined in accordance with subsection 35; and
B is the applicable GHG emissions limit for the covered facility for the compliance period, expressed in CO₂e tonnes, determined in accordance with sections 36, 36.1, 36.2, 41, 41.1, 41.2 or 42.

New covered facilities

(2) If, on January 1 during a compliance period, the covered facility has not completed two calendar years of production following the date of first production, subsection (1) does not apply to the covered facility for that compliance period.

Primary activity

(3) Subsection (2) only applies to a covered facility whose primary activity is a specified industrial activity.

New electricity generation facility

(4) Subsection (2) does not apply to an electricity production facility that begins generating electricity on or after January 1, 2021.

Date of production

(5) For the purposes of subsection (2), to determine the date of first production for a covered facility all industrial activities that the facility has previously been or is currently engaged in must be taken into account.

Records

Content

45 (1) The person responsible for a covered facility must keep a record of the following information with respect to the covered facility and each unit within it, if applicable, for each compliance period

(a) the total quantity of GHGs from each specified emission type;
(b) the quantity of each GHG from each specified emission type;
(c) all data used for a calculation made under these Regulations, for each specified emission type and GHG, including data used to estimate missing data;
(d) all sampling, analysis and measurement data for each specified emission type and GHG;
(e) the methods used to quantify, sample, analyze and measure each specified emission type;
(f) the methods and data used to quantify production;
(g) the procedural changes made in data collection and calculations and changes to measuring devices used to quantify GHGs or production;
(h) the quantity of each GHG not included in the total quantity of GHGs under section 23 and the relevant specified emission type;
(i) the quantities of CO₂ captured, transported or stored expressed in tonnes and the data used to quantify that CO₂;
(j) the output-based standard calculated under section 37 for each specified industrial activity and all methods and data used to calculate that output-based standard;
(k) documents that demonstrate the maintenance, calibration and operation of measuring devices was done in accordance with these Regulations;
(l) if the person responsible for a covered facility sells thermal energy that was produced at the covered facility to other covered facilities or buys thermal energy from other covered facilities,
- (i) the sales invoices or receipts for the thermal energy bought or sold,
- (ii) the name of any covered facility from which thermal energy is bought or to which it is sold and the covered facility certificate number that was issued to the covered facility, and
- (iii) the methods and data used to quantify the quantity of thermal energy bought or sold and the data in relation to the ratio of heat from the combustion of fossil fuel;
(m) any errors or omissions identified and the measures taken to correct them, with all supporting data and documentation;
(n) a copy of all permits issue pursuant to section 28; and
(o) documentation that demonstrates that the CO₂ was captured, transported and stored in accordance with the laws of Canada or a province or of the United States or one of its States.

CEMS

(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 section 8 of the Reference Method for Source Testing: Quantification of Carbon Dioxide Releases by Continuous Emission Monitoring Systems from Thermal Power Generation, published by the Department of the Environment in 2012.

Availability of information

(3) The record must be kept within 30 days after the information becomes available.

Electronic submission

46 (1) Any information that is required to be provided to the Minister under these Regulations with respect to a covered facility must be submitted electronically in the form and format specified by the Minister and must bear the electronic signature of the person responsible for the covered facility or of their authorized official.

Provision on paper

(2) If the Minister has not specified an electronic form and format or if it is not feasible to submit the information in accordance with subsection (1) because of circumstances beyond the control of the person responsible for the covered facility or their authorized official, the information must be submitted on paper, signed by the person responsible for the covered facility or their authorized official, in the form and format specified by the Minister. However, if no form and format has been so specified, it may be in any form and format.

Retention of information

47 (1) The person responsible for a covered facility must retain any record kept under section 45 and a copy of information submitted to the Minister under these Regulations, including any calculations, measurements and other data on which the records or information is based.

Location of records

(2) The records, copies and documents must be retained at the principal place of business in Canada of the person responsible for the covered facility or, on notification to the Minister, at any other place in Canada where they can be inspected.

Relocation of records

(3) If the records, copies or supporting documents are moved, the person responsible for the covered facility must notify the Minister, in writing, of the civic address of the new location within 30 days after the day of the move.

Obligation to notify

48 The person responsible for the covered facility must notify the Minister, in writing, within 30 days after a change to any of the following:

(a) the administrative information set out in sections 1 and 2 of Schedules 2 and 5 and provided to the Minister under these Regulations;
(b) the facility’s perimeter;
(c) the information provided in an application for registration under subsection 171(1) of the Act or in a request for designation under subsection 172(1) of the Act; or
(d) the information provided in an application for a permit under section 27, if the permit is still valid.

Verification Report

Verification body

49 (1) To be authorized to verify an annual report or a corrected report, a third party must

(a) meet the following accreditation requirements:
- (i) it is accredited as a verification body to the ISO Standard 14065 by the Standards Council of Canada, the American National Standards Institute or any other accreditation organization that is a member of the International Accreditation Forum,
- (ii) it has a scope of accreditation that is sufficient to verify the annual report or the corrected report, and
- (iii) it is not suspended by an accreditation organization that issued an accreditation; and
(b) conduct the verification in accordance with ISO Standard 14064-3 published by the International Organization for Standardization in 2006 entitled Greenhouse gases — Part 3: Specification with guidance for the validation and verification of greenhouse gas assertions or published in 2019 entitled Greenhouse gases — Part 3: Specification with guidance for the verification and validation of greenhouse gas statements, based on 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
- (i) a material discrepancy exists with respect to the total quantity of GHGs and production reported in the annual report from each specified industrial activity that is used in the calculation of the emissions limit, and
- (ii) in the verification body’s opinion, the annual report or corrected report was prepared in accordance with these Regulations.

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 50 kt of CO₂e during the compliance period,
- (i) in the case of each 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 8%:

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 8%:

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 of equal to or greater than 50 kt of CO₂e but less than 500 kt during the compliance period,
- (i) in the case of each 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;
(c) 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 each single 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
(d) with respect to the production from each specified industrial activity that is used in the calculation of the emissions limit, in the case 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 specified industrial activity in question that is reported in the annual report or corrected report, expressed in the applicable unit of measure.

Conflict of interest

50 (1) The person responsible for a covered facility must ensure that no real or potential conflict of interest exists between the person and the accredited verification body, including members of the verification team and any individual or corporate entity associated with the verification body, that is a threat to or compromises the verification body’s impartiality that cannot be effectively managed.

Consecutive verifications

(2) The person responsible must not have their annual report verified by a verification body that has verified six consecutive annual reports prepared under these Regulations with respect to the same covered facility, unless three years have elapsed since the last of those reports was verified. However, a corrected report may be verified by the verification body within those three years if it is in relation to an annual report verified by that verification body.

Facility visit

51 (1) Subject to subsection (2), the person responsible for a covered facility must ensure that their covered facility is visited by an accredited verification body in the following situations:

(a) it is the initial verification of the covered facility under these Regulations or by the verification body;
(b) at least three calendar years have passed since the verification body has verified an annual report for the covered facility;
(c) in the last annual report for the covered facility prepared under these Regulations, the verification body made a determination
- (i) that a material discrepancy exists with respect to the total quantity of GHGs or production reported in the annual report from a specified industrial activity that is used in the calculation of the emissions limit, or
- (ii) that the annual report was not prepared in accordance with these Regulations; or
(d) the verification body is of the opinion a site visit is required.

Other visits

(2) If buildings that are used for legal, administrative or management purposes are not located where an industrial activity is carried out, the person responsible for a covered facility must ensure that the verification body visits those buildings if data or information necessary for verifying an annual report or a corrected report is kept in those buildings.

Content of verification report

52 A verification report is prepared by a verification body in relation to the annual report and corrected report, if applicable, and any related data and information, and includes the information contained in Schedule 5.

Compensation and Compliance Units

Minister’s Intervention

Determination

53 (1) Despite what is set out in a covered facility’s annual report or corrected report for a compliance period, 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 GHGs from the covered facility or the production from one or more specified industrial activity used in the calculation of the emissions limit reported in the annual report or the corrected report; or
(b) the verification statement referred to in paragraph 3(n) of Schedule 5 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.

Criteria

(2) The Minister is to establish the emissions limit or determine the quantity of GHGs emitted from the covered facility for the compliance period, as the case may be, based on the following:

(a) the annual report and verification report for the compliance period and, if necessary, any previous reports;
(b) any report made in accordance with the Notice with respect to reporting of greenhouse gases (GHGs) published under the Canadian Environmental Protection Act, 1999;
(c) information in respect of industrial activities, in Canada or in other jurisdictions, similar to those of the covered facility, that allows for the determination of production amounts for the covered facility;
(d) accepted quantification methods used to calculate the GHGs from facilities engaged in the same industrial activity or in the same type of industrial activity as the covered facility; and
(e) any other information provided, on the Minister’s request, by the person responsible for the covered facility or the verifier.

Notice

(3) The Minister must notify the person responsible for the covered facility, in writing, of their determination with respect to the emissions limit or the quantity of GHGs emitted from the covered facility established for the compliance period.

Compensation and Issuance of Surplus Credits

Excess emissions

54 For the purposes of subsection 174(1) of the Act, if, during a compliance period, a covered facility emits GHGs in a quantity that exceeds the applicable emissions limit, the compensation to be provided by the person responsible for that facility is to be established based on the quantity of GHGs, expressed in CO₂e tonnes, that was emitted in excess of the emissions limit as reported in the annual report submitted for the compliance period or the Minister’s determination under section 53, as the case may be.

Excess emissions charge payment

55 (1) Any compensation that is provided by means of an excess emissions charge payment must be made electronically to the Receiver General for Canada.

Surplus credits

(2) Any compensation that is provided by means of a remittance of surplus credits must be made in the manner set out in section 70.

Other compliance units

(3) Any compensation that is provided by means of a remittance of compliance units other than surplus credits must be made in the manner set out in section 71.

Minimum percentage — charge

56 A minimum of 25% of the compensation that is required under section 174 of the Act must be provided by means of an excess emissions charge payment.

Regular-rate compensation deadline

57 (1) For the purposes of subsection 174(3) of the Act, the regular-rate compensation deadline is December 15 of the calendar year in which the related annual report must be submitted.

Increased-rate compensation deadline

(2) For the purposes of subsection 174(4) of the Act, the increased-rate compensation deadline is February 15 of the calendar year following the deadline under subsection (1).

Notice referred to in subsection 53(3)

(3) However, if a notice of determination under subsection 53(3) is issued after October 31 of the year in which the related annual report is due

(a) the regular-rate compensation deadline is 45 days after the day on which the notice is issued; and
(b) the increased-rate compensation deadline is 60 days after the day on which the regular-rate compensation deadline under paragraph (a) expires.

Compensation information

58 A person that is responsible for a covered facility must, at the time compensation is provided, submit to the Minister the following information:

(a) the covered facility certificate number;
(b) the provision of the Act under which the compensation is being provided;
(c) the compliance period for which compensation is being provided;
(d) the quantity of GHGs emitted in excess of the emissions limit in respect of which the compensation is provided, expressed in CO₂e tonnes;
(e) the details of any excess emissions charge payment, including
- (i) the amount in dollars paid to the Receiver General for Canada,
- (ii) the applicable rate, and
- (iii) the date of payment;
(f) the details of any surplus credits or offset credits remitted, including, for each type of credit,
- (i) the number remitted,
- (ii) the date of the remittance transaction,
- (iii) the remittance transaction number,
- (iv) the serial numbers, and
- (v) the date or dates on which they were issued; and
(g) the details of any units or credits, recognized as compliance units, remitted, including
- (i) the number remitted,
- (ii) the province or territory or program authority referred to in subsection 78(1) that issued the units or credits,
- (iii) the date of their retirement,
- (iv) the serial numbers assigned to them by the province or territory or program authority referred to in subsection 78(1),
- (v) the start date of the offset project for which the unit or credit was issued,
- (vi) the year in which the GHG reduction or removal occurred for which the unit or credit was issued,
- (vii) the offset protocol applicable to the project for which the unit or credit was issued, including the version number and publication date, and
- (viii) the name of the accredited verification body that verified the units or credits.

Surplus credits

59 For the purposes of section 175 of the Act, 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, provided that no material discrepancy, within the meaning of subsection 49(2), exists with respect to the total quantity of GHGs and the production from each specified industrial activity that is used in the calculation of the emissions limit.

Errors and Omissions

Identification by person responsible

61 The notice submitted under subsection 176(1) of the Act by a person responsible for a covered facility who has become aware of an error or omission in an annual report must indicate whether

(a) the error or omission would have constituted a material discrepancy under subsection 49(2) if it had been identified during the verification of the annual report; and
(b) the aggregate of all errors and omissions would have constituted a material discrepancy under subsection 49(2) if it had been identified during the verification of the annual report.

Corrected report

62 (1) The person responsible for the covered facility must submit to the Minister a corrected report within 60 days after the day on which the notice is submitted or, if the notice indicated that the error or omission, or the aggregate of all errors or 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, within 90 days after the day on which the notice is submitted.

Content

(2) The corrected report must include the following information:

(a) a description of the corrections made to the annual report;
(b) the circumstances that led to the error or omission and the reasons why the error or omission was not previously detected;
(c) a description of the measures implemented, or to be implemented, to avoid future errors or omissions of the same type;
(d) the quantity of GHGs to which the detected error or omission corresponds, if corrected;
(e) the production to which the detected error or omission corresponds, if corrected;
(f) the result of the calculation under section 64;
(g) in the case of a covered facility other than one referred to in paragraph (h) or (i)
- (i) the quantity of each GHG from the covered facility, expressed in CO₂e tonnes, for each emission type determined in accordance with subsections 17(2) to (4), if corrected,
- (ii) the total quantity of GHGs determined in accordance with section 17, if corrected,
- (iii) the quantity of GHGs emitted and the quantity of CO₂ that is captured and stored, determined in accordance with section 35, if corrected, and
- (iv) the quantity of production quantified in accordance with section 31, if corrected;
(g.1) in the case of a covered facility to which section 36.2 applies, the information referred subsection 11(1.1), if corrected;
(h) in the case of an electricity generation facility
- (i) the quantity of each GHG from the covered facility, expressed in CO₂e tonnes, for each emission type, if corrected,
- (ii) the total quantity of GHGs from each unit within the facility, determined in accordance with section 20, if corrected, and the sum of those GHGs from all units within the covered facility during the compliance period, if corrected,
- (iii) the quantity of GHGs emitted and the quantity of CO₂ that is captured and stored, determined in accordance with section 35, if corrected, and
- (iv) the gross quantity of electricity generated by each unit within the facility, quantified in accordance with section 32, if corrected.
(i) in respect of a covered facility where both the specified industrial activity of producing coal by mining coal deposits and, if comprised of a unit or a group of units that are registered under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, the generation of electricity are engaged in,
- (i) the quantity of each GHG from the covered facility, expressed in CO₂e tonnes, from each specified emission type, if corrected,
- (ii) the total quantity of GHGs from mining of coal deposits, determined in accordance with section 17, and the total quantities of GHGs from the generation of electricity, determined in accordance with section 20, if corrected,
- (iii) the quantity of GHGs emitted and the quantity of CO₂ that is captured and stored, determined in accordance with section 35, if applicable, if corrected, and
- (iv) the production quantified for each specified industrial activity engaged at the facility, the corrected production by each unit within the covered facility for each of the industrial activities set out in paragraphs 38(a) to (c), column 1, of Schedule 1 during the compliance period and the corrected sum of the production from all of the units, if corrected;
(i.i) in the case of a covered facility to which section 41.2 applies, the information referred to in subsection 11(1.2), if corrected;
(j) any change to the result obtained under section 44; and
(k) any other correction made to the information in the annual report.

Identification by the Minister

63 (1) Subsection 62(2) applies to a report that is required by the Minister under subsection 177(2) of the Act and the report must be submitted to the Minister within the following period:

(a) in the case of a corrected report, 60 days after the day on which the Minister required it; and
(b) in the case of a verified corrected report, 90 days after the day on which the Minister required it.

Verification report

(2) The corrected report submitted under paragraph (1)(b) must be submitted with a verification report prepared in accordance with section 52.

Change in obligations

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

Revised compensation

65 (1) 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 specified in section 64 is greater than, or equal to, 500 CO₂e tonnes.

Issuance of surplus credits

(2) For the purposes of paragraph 178(1)(b) of the Act, the Minister may issue to a person that is responsible for a covered facility a number of surplus credits that is equivalent to the difference between

(a) the number of surplus credits calculated based on the corrected report and the number of surplus credits issued under section 175 of Act based on the annual report; or
(b) the applicable emissions limit and the quantity of GHGs emitted from the facility that are reported in the corrected report.

Excess Surplus credits issued

66 (1) If a corrected report shows that an excess number of surplus credits was issued to the person responsible for a covered facility and the credits in question remain in an account in the tracking system that is linked to the covered facility, the Minister must revoke the excess credits without notice. The revocation is effective as of the date on which the corrected report is submitted.

Insufficient surplus credits in account

(2) If any of the excess surplus credits are no longer in an account in the tracking system that is linked to the covered facility, the person responsible for the facility must, within the compensation deadlines set out in subsections 69(1) and (2), make up the amount owed by

(a) remitting to the Minister other surplus credits in accordance with section 70;
(b) remitting to the Minister other compliance units in accordance with section 71; or
(c) making an excess emissions charge payment in accordance with section 55.

Charge

67 An excess emissions charge payment made for the purposes of subsection 65(1) must be made in the manner set out in section 55.

Surplus credits

68 (1) Any revised compensation that is provided by the remittance of surplus credits must be made in the manner set out in section 70.

Other compliance units

(2) Any revised compensation that is provided by the remittance of compliance units other than surplus credits must be made in the manner set out in section 71.

Regular-rate compensation deadline

69 (1) For the purposes of 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 is submitted.

Increased-rate compensation deadline

(2) If compensation is not provided in full by the deadline set out in subsection (1), the increased rate referred to in subsection 174(4) of the Act applies for a period of 60 days after that deadline.

Other compensation deadlines

(3) If a corrected report is submitted to the Minister in respect of a compliance period for which the regular-rate compensation deadline set out in subsection 57(1) has not expired, the compensation deadline in respect of that compliance period is the later of

(a) the compensation deadlines set out in subsection 57(1) or (2), as the case may be, and
(b) the compensation deadlines under subsection (1) or (2), as the case may be.

Remittance of Compliance Units

Surplus credits

70 Any surplus credit may be remitted to the Minister for the purposes of subsection 174(1) or paragraph 178(1)(a) of the Act if the credit was issued no more than five calendar years before the remittance.

Other compliance units

71 Any recognized unit or credit or offset credit may be remitted to the Minister for the purposes of subsection 174(1) or paragraph 178(1)(a) of the Act if the unit or credit, as the case may be, was issued for GHG reductions or removals that occurred no more than eight calendar years before the remittance.

Suspension and Revocation

Suspension

72 (1) For the purposes of subsection 180(1) of the Act, the Minister may suspend a surplus credit or offset credit in an account if the Minister has reasonable grounds to believe that the credit

(a) was already used;
(b) was issued on the basis of false or misleading information; or
(c) is no longer valid.

Notice

(2) The Minister must, without delay, notify the holder of the account of the suspension of the credit, the reasons for the suspension and the date on which it takes effect.

Response

(3) The holder of the account may, within 30 days after the day on which the Minister’s notice under subsection (2) is issued, submit to the Minister their reasons why the credit should not be suspended.

Revocation

73 The Minister must, after the period set out in subsection 72(3), thoroughly review the reasons for the suspension and notify the holder of the account that

(a) if the Minister determines that the reasons for the suspension are well-founded, the surplus credit or offset credit is revoked; or
(b) the suspension of the credit is lifted.

Request for cancellation

74 A request under subsection 180(2) of the Act to cancel a surplus credit or offset credit must be made to the Minister in writing and include the serial number of the credit to be cancelled.

Issuance Error or Invalidity

Application of subsection 181(1) of the Act

75 (1) If the Minister requires a person, under subsection 181(1) of the Act, to remit a compliance unit, the Minister must provide the person a notice indicating the reason for the remittance, the number of compliance units to be remitted and the deadline by which the remittance is to be made.

Manner of remittance

(2) The compliance units remitted to the Minister under subsection 181(2) of the Act must

(a) in the case surplus credits, have been issued within five calendar years before the deadline indicated in the notice provided under subsection (1); and
(b) in the case of recognized units or credits or offset credits, have been issued for GHG reductions or removals that occurred within the eight calendar years before the deadline indicated in the notice provided under subsection (1).

Tracking System

Accounts for participants

76 For the purposes of subsection 186(1) of the Act, any person, other than a person responsible for a covered facility, who wishes to open an account in the tracking system must notify the Minister in writing. The Minister must send to the person the conditions related to the use of that account in accordance with subsection 186(2) of the Act.

Notice of closure

77 (1) If an account has been inactive for more than seven years, the Minister may give 60 days’ notice to the holder of the account of the Minister’s intent to close the account.

Closing of account

(2) If the holder of the account fails to request that the account remain open before the expiry of the 60 days, the Minister may close the account under subsection 186(3) of the Act.

Recognized Units or Credits

Compliance unit

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

(a) by a province or territory or by a program authority on behalf of a province or territory; and
(b) under an offset protocol and offset program that is set out on the list published on the Department of the Environment’s website.

Offset programs

(2) In establishing the list of offset programs, the Minister must ensure that each one includes the following elements:

(a) rules regarding governance, oversight and enforcement;
(b) rules regarding registration and renewal of projects;
(c) rules regarding the establishment of periods within which units or credits may be issued;
(d) rules regarding who is entitled to the credit or unit for the GHG reductions or removals;
(e) measures to ensure that GHG reductions and removals are additional and permanent and that reversal risks have been mitigated;
(f) measures to ensure that, for a GHG reduction or removal of one CO₂e tonne, no more than one credit or unit is issued and the unit or credit is not used more than once;
(g) publicly available information on projects, protocols and units or credits; and
(h) a requirement that, prior to the issuance of a unit or credit, there be a verification by a third party in accordance with procedures that allow them to determine with a reasonable level of assurance that the associated project meets the requirements of the protocol and program.

Offset protocols

(3) In establishing the list of offset protocols recognized under a program referred to in subsection (2), the Minister must verify that each protocol ensures that

(a) the reduction or removal is with respect to a GHG;
(b) the reduction or removal is not subject to carbon pollution pricing;
(c) the GHG reduction or removal is quantified using scientifically-established methods that allow for
- (i) the calculation of the quantity of GHG emissions or removals for each GHG source, sink and reservoir,
- (ii) the quantification of reversals,
- (ii.1) the assessment of leakage risks,
- (iii) the calculation of the quantity of GHG reductions or removals that would not have occurred in comparison with the baseline scenario, and
- (iv) the use of conservative quantification assumptions and approaches;
(c.1) the baseline scenario used reflects the most recent data available, any legal requirements and current practices with respect to the activity that is the subject of the protocol;
(d) best practices are used for
- (i) data gathering and management,
- (ii) record keeping,
- (iii) the ongoing monitoring of offset projects, including permanence, and
- (iv) quality assurance and quality control; and
(e) the GHG global warming potentials used in calculations are less than or equal to those set out in column 2 of Schedule 3 to the Act.

Recognized unit or credit

(4) A recognized unit or credit must, at the time of its remittance to the Minister,

(a) be valid;
(b) have been issued in respect of a project that uses a protocol referred to in subsection (3);
(c) have been issued in respect of a project located in Canada that began in 2017 or later; and
(d) have been verified by a verification body that
- (i) is accredited as a verification body to the ISO Standard 14065 by the Standards Council of Canada, the American National Standards Institute or any other accreditation organization that is a member of the International Accreditation Forum, and
- (ii) is not suspended by the accreditation organization that issued its accreditation.

Transitional Provisions

Subsection 12(3)

79 For the 2019 calendar year, despite subsection 12(3), if a covered facility where a specified industrial activity set out in items 2 or 3, column 1, of Schedule 1 is engaged in produces hydrogen gas, the person responsible for the covered facility must include in their annual report the information referred to in that subsection if it is available.

Application

80 Section 8 of the Greenhouse Gas Emissions Information Production Order, as it read immediately before August 1, 2019, continues to apply, with any necessary modifications, with respect to a person responsible for a covered facility where an industrial activity set out in Schedule 1 to these Regulations is engaged in until January 1, 2020.

Records

81 (1) Any records kept in accordance with section 11 of the Greenhouse Gas Emissions Information Production Order, as it read immediately before August 1, 2019, during the period beginning on January 1, 2019 and ending on August 1, 2019, are deemed to be records kept for the purposes of subsection 45(1) of these Regulations.

Alternative method

(2) For the 2019 calendar year, if a person responsible for a covered facility used an alternative sampling, measurement or analysis method for a specified emission type in accordance with section 8 of the Greenhouse Gas Emissions Information Production Order, as it read before August 1, 2019, they must keep a record of a description of that method.

Clinker

82 For the 2019 calendar year, despite paragraph 31(1)(a) of these Regulations, the production from a covered facility with respect to the specified industrial activity set out in paragraph 7(a), column 1, of Schedule 1 of these Regulations may be quantified under paragraph 36(c) of the Greenhouse Gas Emissions Information Production Order, as it read immediately before August 1, 2019. If the production is quantified under the Order, it cannot be used in the calculation of the emissions limit under subsection 36(1) of these Regulations.

Glass containers

83 For the 2019 calendar year, despite paragraph 31(1)(a) and subsection 36(1) of these Regulations, the production from a covered facility with respect to the specified industrial activity set out in paragraph 9(a), column 1, of Schedule 1 to these Regulations may be quantified in accordance with section 103.2 of the Greenhouse Gas Emissions Information Production Order, as it read before August 1, 2019.

High value chemicals

84 For the 2019 calendar year, despite paragraph 31(1)(a) of these Regulations, the production from a facility with respect to the specified industrial activity set out in paragraph 17(a), column 1, of Schedule 1 to these Regulations may be quantified in accordance with section 103.36 of the Greenhouse Gas Emissions Information Production Order, as it read before August 1, 2019.

Isopropyl alcohol

85 For the 2019 calendar year, despite subparagraph 11(1)(a)(ii) of these Regulations, the person responsible for the covered facility is not required to quantify the production from the specified industrial activity set out in paragraph 3(c), column 1, of Schedule 1.

Pulp and Paper

85.1 (1) For the 2019 calendar year, despite paragraph 31(1)(a) and subsection 36(1) of these Regulations, the production from a covered facility with respect to the specified industrial activity set out in paragraph 36(c), column 1, of Schedule 1 to these Regulations may be quantified in accordance with section 102 of the Greenhouse Gas Emissions Information Production Order, as it read before August 1, 2019. In that case, the output-based standards that apply are

(a) 0.203 CO₂e tonnes per unit of measurement, in the case of a facility equipped with a recovery boiler, lime kiln or pulping digester, and
(b) 0.184 CO₂e tonnes per unit of measurement, in the case of a facility not equipped with a recovery boiler, lime kiln or pulping digester.

Reporting

(2) For the 2019 calendar year, if a covered facility where the specified industrial activity set out in paragraph 36(c), column 1, of Schedule 1 to these Regulations is engaged in quantifies production in accordance with subsection (1), the annual report must include the quantity of specialty products produced, in tonnes, if that information is available.

Amendments to the Environmental Administrative Monetary Penalties Regulations

86 Section 2 of the Environmental Violations Administrative Monetary Penalties Regulations^{footnote 1} is amended by adding the following after subsection (3):

Other provisions

(4) The contravention of subsection 174(1) or paragraph 178(1)(a) of the Greenhouse Gas Pollution Pricing Act is designated as a violation that may be proceeded with in accordance with the Act.

87 Section 3 of the Regulations is replaced by the following:

Types of violations

3 The contravention of a provision set out in column 1 of Schedule 1, of an order or direction made under a provision set out in column 1 of Schedule 2 or of a condition referred to in a provision set out in column 1 of Schedule 3 is classified as a Type A, B, C, D or E violation in accordance with column 2 of the respective schedule.

88 Sections 4 and 5 of the Regulations are replaced by the following:

Formula — Type A, B or C

4 (1) The amount of the penalty for each Type A, B or C violation is to be determined by the formula

W + X + Y + Z

where

W is the baseline penalty amount determined under section 5;
X is the history of non-compliance amount, if any, as determined under section 6;
Y is the environmental harm amount, if any, as determined under section 7; and
Z is the economic gain amount, if any, as determined under section 8.

Formula – types D or E

(2) The amount of the penalty for each Type D or E violation is to be determined by the formula

W + X + Y

where

W is the baseline penalty amount determined under section 5;
X is the history of non-compliance amount, if any, as determined under section 6; and
Y is the economic gain amount, if any, as determined under section 8.1.

Baseline penalty amount

5 The baseline penalty amount for a violation is the amount set out in column 3 of Schedule 4 or of Schedule 5 that corresponds to the category of the violator and the type of violation committed as set out in columns 1 and 2, respectively, of the applicable schedule.

89 (1) Subsection 6(1) of the Regulations is replaced by the following:

History of non-compliance amount

6 (1) If the violator has a history of non-compliance, the history of non-compliance amount is the amount set out in column 4 of Schedule 4 or of Schedule 5 that corresponds to the category of the violator and the type of violation committed as set out in columns 1 and 2, respectively, of the applicable Schedule.

(2) Paragraph 6(2)(c) of the Regulations is amended by striking out “or” at the end of paragraph (b) and by replacing paragraph (c) with the following:

(c) the commission of a violation relating to the Greenhouse Gas Pollution Pricing Act or a regulation made under that Act, they were subject to an enforcement action in relation to that Act or any of those regulations; or
(d) the commission of a violation relating to any Environmental Act, other than the Canadian Environmental Protection Act, 1999 or the Greenhouse Gas Pollution Pricing Act, or a regulation made under one of those Acts, they were subject to an enforcement action in relation to that Act or any of that Act’s regulations.

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

Economic advantage amount

8.1 If the violation has resulted in economic gain to the violator, including an avoided financial cost, the applicable economic gain amount is the amount set out in column 5 of Schedule 5 that corresponds to the category of the violator and the type of violation committed as set out in columns 1 and 2, respectively, of that Schedule.

Specific case

8.2 (1) Subject to subsection (2), the amount of the penalty for a violation referred to in subsection 2(4) is $0.25.

Continued violation

(2) If a violation referred to in subsection (1) is continued on more than one day, the penalty in respect of each of the separate violations that, because of section 12 of the Act, result from that continuation shall be

(a) $0.25 for one that is committed during the nine-day period beginning on the day after the day of the contravention;
(b) $0.50 for one that is committed during the 10-day period beginning on the tenth day following the day of the contravention; and
(c) $1.00 for one that is committed on or after the twenty-first day following the contravention.

91 Schedule 1 to the Regulations is amended by adding the following after Part 6:

PART 7

Greenhouse Gas Pollution Pricing Act and its Regulations

DIVISION 1

Greenhouse Gas Pollution Pricing Act
Item	Column 1 Provision	Column 2 Violation Type
1	171(1)	D
2	173(a)	E
3	173(b)	E
4	176(1)	D
5	176(2)(a)	D
6	176(2)(b)	D
7	177(2)	D
8	181(2)	E
9	181(3)	E
10	186(1)	D
11	187(1)	D
12	187(3)	D
13	187(4)	D
14	187(5)	D
15	187(6)	D
16	197(4)	E
17	199(2)(a)	E
18	199(2)(b)	E
19	205(2)	E

DIVISION 2

Output-based Pricing System Regulations
Item	Column 1 Provision	Column 2 Violation Type
1	7(3)	E
2	11	E
3	12	E
4	13	E
5	16(2)(a)	E
6	16(3)(a)	E
7	16(4)(a)	E
8	16(5)(a)	E
9	16(6)(a)	E
10	16(7)(a)	E
11	16(8)(a)	E
12	17(4)	E
13	18	E
14	25	E
15	35	E
16	36	E
17	36.1	E
18	36.2	E
19	36.3	E
20	37	E
21	41	E
22	41.1	E
23	41.2	E
24	41.3	E
25	45(1)	D
26	45(2)	D
27	47(1)	D
28	47(2)	D
29	47(3)	D
30	48	D
31	50(1)	E
32	50(2)	E
33	51(1)	D
34	51(2)	D
35	55(1)	D
36	55(2)	D
37	55(3)	D
38	56	E
39	58	D
40	61	E
41	62(1)	E
42	62(2)	E
43	63(1)(a)	D
44	63(1)(b)	D
45	63(2)	D
46	66(2)(a)	E
47	66(2)(b)	E
48	66(2)(c)	E
49	67	D
50	68	D
51	69	D
52	70	E
53	71	E

92 The Regulations are amended by adding, after Schedule 4, the Schedule 5 set out in the schedule to these Regulations.

Coming into Force

January 1, 2019

93 (1) Subject to subsections (2) to (6), these Regulations are deemed to have come into force on January 1, 2019.

July 1, 2019

(2) These Regulations apply in Yukon and Nunavut on July 1, 2019.

January 1, 2020

(3) Sections 26 to 30 and subsections 31(2) and (3) come into force on January 1, 2020.

August 1, 2019

(4) Subsection 45(2) of these Regulations comes into force on August 1, 2019.

February 16, 2023

(5) Section 56 comes into force on February 16, 2023.

February 16, 2021

(6) Section 76 comes into force on February 16, 2021.

SCHEDULE 1

(Subsection 5(2), paragraph 8(b), subparagraphs 11(1)(b)(iii) and (iv), clauses 11(1)(c)(iii)(A) and (B), subsections 12(2) and (3) and 16(1) to (8), paragraphs 17(2)(a) and (c), subsections 22(2), 31(1), 32(1), 36(1) to (4), 36.1(1) and (2), 36.2(2) and 37(1) and (2), sections 38 to 40, subsections 41(1) and (2), 41.1(2) and 41.2(2), section 42, subparagraph 62(2)(i)(iv), section 2 of Part 4 of Schedule 3, sections 1 and 2 of Part 7 of Schedule 3 and subparagraphs 3(g)(ii) and 3(h)(iii) of Schedule 5)

Industrial Activities and Output-based Standards

TABLE
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
Oil and Gas Production
1	Bitumen and other crude oil production — other than bitumen extracted from surface mining — by a covered facility other than a covered facility referred to in item 3
	(a) extraction, processing and production of light crude oil (having a density of less than 940 kg/m³ at 15°C)	barrels of light crude oil	0.0159	Part 1
	(b) extraction, processing and production of bitumen or other heavy crude oil (having a density greater than or equal to 940 kg/m³ at 15°C)	barrels of bitumen and heavy crude oil	0.0544	Part 1
2	Upgrading of bitumen or heavy oil to produce synthetic crude oil	barrels of synthetic crude oil	0.0408	Part 2
3	Processing of crude oil or secondary petroleum products at a covered facility that has a combined annual volume of gasoline, diesel fuel and lubricant basestock produced that is greater than 40% of its annual volume of liquid petroleum products produced
	(a) refining of crude oil, including bitumen, heavy crude oil, light crude oil or synthetic crude oil	complexity-weighted barrels	0.00420	Part 3
	(b) production of lubricant basestock	kilolitres of lubricant basestock	0.295	Part 3
	(c) production of isopropyl alcohol	tonnes of isopropyl alcohol	calculated in accordance with section 37 of these Regulations	Part 3
4	Processing of natural gas and production of
	(a) pipeline-transmission-quality natural gas	100 000 cubic metres of pipeline-transmission-quality natural gas at a temperature of 15°C and a pressure of 101.325 kPa	10.6	Part 4
	(b) natural gas liquids	cubic metres of propane and butane combined at a temperature of 15°C and at an equilibrium pressure	0.0301	Part 4
5	Transmission of processed natural gas by a facility referred to in paragraph (b) of the definition facility in subsection 1(1) of these Regulations	Megawatt hours (MWh)	0.393	Part 5
6	Production of hydrogen gas using steam hydrocarbon reforming or partial oxidation of hydrocarbons	Tonnes of hydrogen gas	9.84	Part 6
Mineral Processing
7	Production of clinker and cement
	(a) clinker	tonnes of clinker	0.799	Part 7
	(b) grey cement	tonnes of grey cement	0.733	Part 7
	(c) white cement	tonnes of white cement	calculated in accordance with section 37 of these Regulations	Part 7
8	Production of lime from limestone using a kiln
	(a) high-calcium lime	tonnes of high-calcium lime produced and lime kiln dust sold	1.20	Part 8
	(b) dolomitic lime	tonnes of dolomitic lime produced and lime kiln dust sold	calculated in accordance with section 37 of these Regulations	Part 8
	(c) speciality lime	tonnes of speciality lime produced	calculated in accordance with section 37 of these Regulations	Part 8
9	Production of glass, including glass wool insulation, using a furnace,
	(a) glass containers	tonnes of packed glass	0.370	Part 9
	(b) glass, other than glass containers	tonnes of glass	calculated in accordance with section 37 of these Regulations	Part 9
10	Production of gypsum products that contain at least 70 weight percent of calcium sulphate dihydrate	tonnes of gypsum products that contain at least 70 weight percent calcium sulphate dihydrate	calculated in accordance with section 37 of these Regulations	Part 10
11	Production of mineral wool insulation, excluding glass wool insulation	tonnes of mineral wool insulation	calculated in accordance with section 37 of these Regulations	Part 11
12	Production of brick or other products made from clay or shale using a kiln	tonnes of brick and other products made from clay or shale using a kiln	0.223	Part 12
Chemicals
13	Production of grain ethanol for use as fuel and secondary production of ethanol for industrial use
	(a) ethanol to be used as fuel	kilolitres of absolute ethanol	0.321	Part 13
	(b) ethanol to be used in industrial applications	kilolitres of absolute ethanol	0.728	Part 13
14	Production of furnace black in any form, including pellets and powders, using thermal oxidation or thermal decomposition of hydrocarbons	tonnes of furnace black	2.08	Part 14
15	Production of 2-methylpenta-methylenediamine (MPMD)	tonnes of MPMD	4.65	Part 15
16	Production of nylon 6 or nylon 6,6, as the case may be
	(a) resins of nylon 6 or nylon 6,6	tonnes of nylon resins	0.480	Part 16
	(b) fibres of nylon 6 or nylon 6,6	tonnes of nylon fibres	0.711	Part 16
17	Production of the following petrochemicals from petroleum and liquefied natural gas or from feedstocks derived from petroleum:
	(a) high-value chemicals that are produced from steam cracking, including hydrogen gas, ethylene, propylene, butadiene and benzene produced from pyrolysis gas	tonnes of high-value chemicals from steam cracking	0.652	Part 17
	(b) aromatic cyclic hydrocarbons, including benzene produced from catalytic reforming	tonnes of aromatic cyclic hydrocarbons	0.694	Part 17
	(c) higher olefins	tonnes of higher olefins	0.954	Part 17
	(d) hydrocarbon solvents	tonnes of hydrocarbon solvents	1.14	Part 17
	(e) styrene	tonnes of styrene	0.925	Part 17
	(f) polyethylene	tonnes of polyethylene	0.164	Part 17
Pharmaceuticals
18	Production of vaccines for human or animal use	litres of vaccine	Calculated in accordance with section 37 of these Regulations	Part 18
Iron, Steel and Metal Tubes
19	Production of steel from feedstock that comes primarily from scrap iron or steel, except the production of metal ingots or the production, using a mould, of metal products of a specific shape or design to produce the intended use of which when in that form is dependent in whole or in part on its shape or design, of
	(a) cast steel	tonnes of cast steel	0.124	Part 19
	(b) rolled steel	tonnes of rolled steel	0.0937	Part 19
20	Production of iron or steel from smelted iron ore or production of metallurgical coke
	(a) production of metallurgical coke in a coke oven battery	tonnes of coke	0.597	Part 20
	(b) production of iron from smelted iron ore	tonnes of iron	1.46	Part 20
	(c) production of steel in a basic oxygen furnace	tonnes of steel	0.164	Part 20
	(d) production of steel in an electric arc furnace	tonnes of steel	Calculated in accordance with section 37 of these Regulations	Part 20
21	Production of iron ore pellets from iron ore concentrate, of
	(a) flux pellets	tonnes of flux pellets	0.0990	Part 21
	(b) pellets other than flux pellets	tonnes of pellets other than flux pellets	0.0560	Part 21
22	Production of metal tubes	tonnes of metal tubes	Calculated in accordance with section 37 of these Regulations	Part 22
Mining and Ore Processing
23	Smelting or refining, from feedstock that comes primarily from ore, of at least one of the following base metals:
	(a) pyrometallurgical smelting of copper	tonnes of copper anodes	calculated in accordance with section 37 of these Regulations	Part 23
	(b) pyrometallurgical smelting and refining of lead	tonnes of lead and lead alloys	2.45	Part 23
	(c) pyrometallurgical smelting of zinc and lead	tonnes of zinc and lead	0.856	Part 23
	(d) pyrometallurgical smelting of nickel	tonnes of nickel matte	0.843	Part 23
	(e) hydrometallurgical refining of base metals, including nickel, copper, zinc, lead and cobalt	tonnes of base metal produced	1.70	Part 23
	(f) hydrometallurgical electrorefining of copper anodes	tonnes of copper cathodes	calculated in accordance with section 37 of these Regulations	Part 23
24	Production of potash from the mining and refining of potash ore using
	(a) a solution mining process	tonnes of potash containing at least 90% potassium chloride	0.232	Part 24
	(b) a conventional underground mining process	tonnes of potash containing at least 90% potassium chloride	0.0382	Part 24
25	Production by mining coal deposits
	(a) of thermal coal	tonnes of thermal coal	calculated in accordance with section 37 of these Regulations	Part 25
	(b) of metallurgical coal	tonnes of metallurgical coal	0.0499	Part 25
26	Production of metal or diamonds from the mining or milling of ore or kimberlite
	(a) production of iron ore	tonnes of iron in ore	0.0169	Part 26
	(b) production of uranium ore concentrate	tonnes of uranium in ore concentrate	9.26	Part 26
	(c) production of silver, platinum or palladium	kilograms of silver, platinum and palladium	Calculated in accordance with section 37 of these Regulations	Part 26
	(d) production of base metal ore concentrate	tonnes of base metals in ore concentrate	0.643	Part 26
	(e) production of diamonds	carats of diamond	0.0172	Part 26
	(f) production of gold	kilograms of gold	7.71	Part 26
27	Calcining of coal to produce char	Tonnes of char	Calculated in accordance with section 37 of these Regulations	Part 27
28	Production of activated carbon from coal	Kilograms of activated carbon	Calculated in accordance with section 37 of these Regulations	Part 28
Nitrogen Fertilizers
29	Production of nitrogen-based fertilizer, including
	(a) nitric acid by the catalytic oxidation of ammonia	tonnes of nitric acid	0.331	Part 29
	(b) anhydrous or aqueous ammonia by the steam reforming of hydrocarbons	tonnes of ammonia	1.82	Part 29
	(c) urea liquor in addition to producing anhydrous ammonia or aqueous ammonia by the steam reforming of hydrocarbons	tonnes of urea liquor	0.162	Part 29
	(d) ammonium phosphate in addition to producing anhydrous ammonia or aqueous ammonia by the steam reforming of hydrocarbons	tonnes of ammonium phosphate	Calculated in accordance with section 37 of these Regulations	Part 29
Food Processing
30	Industrial processing of potatoes for human or animal consumption	Tonnes of potatoes used as raw material	0.0728	Part 30
31	Industrial processing of oilseeds for human or animal consumption	Tonnes of oilseed used as raw material	0.0481	Part 31
32	Production of ethanol from distillation for use in the production of alcoholic beverages	Kilolitres of absolute alcohol	1.11	Part 32
33	Processing of corn through wet milling	Tonnes of corn used as raw material	0.0991	Part 33
34	Production of citric acid	Tonnes of anhydrous citric acid	0.479	Part 34
35	Production of refined sugar from raw cane sugar	Tonnes of refined sugar	0.102	Part 35
Pulp and Paper
36	Production of pulp and other products
	(a) pulp from wood, other plant material or paper or any product derived directly from pulp or a pulping process — excluding specialty products — at a facility equipped with a recovery boiler, lime kiln or pulping digester	tonnes of finished product	0.203	Part 36
	(b) pulp from wood, other plant material or paper or any product derived directly from pulp or a pulping process — excluding specialty products — at a facility not equipped with a recovery boiler, lime kiln or pulping digester	tonnes of finished product	0.184	Part 36
	(c) production of specialty products from wood, other plant material or paper or any product derived directly from pulp or a pulping process, namely abrasive paper base, food grade grease resistant paper, packaging waxed paper base, paper for medical applications, napkin paper for commercial use, towel papers for commercial or domestic use, bath paper for domestic use, facial paper for domestic use or dissolving pulp for viscose	tonnes of specialty product	Calculated in accordance with section 37 of these Regulations	Part 36
Automotive
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)	Number of vehicles	0.216	Part 37
Electricity Generation
38	Generation of electricity
	(a) using solid fuels	gigawatt hours (GWh)	800 in 2019 650 in 2020 622 in 2021 594 in 2022 566 in 2023 538 in 2024 510 in 2025 482 in 2026 454 in 2027 426 in 2028 398 in 2029 370 in 2030 and after	Part 38
	(b) using liquid fuels	gigawatt hours (GWh)	550	Part 38
	(c) using gaseous fuels	gigawatt hours (GWh)	370	Part 38

SCHEDULE 2

(Subsection 11(1))

Content of Annual Report on Emissions and Production

1 Information with respect to the person responsible for the covered facility:

(a) an indication as to whether they own or are otherwise responsible for the covered facility, including having the charge, management or control of the facility, or are the true decision maker with respect to the facility’s operations;
(b) their name (including any trade name or other name used by them) and civic address;
(c) the name, title, civic and postal addresses, telephone number and, if any, email address of their authorized official;
(d) the name, title, civic and postal addresses, telephone number and, if any, email address of a contact person, if different from the authorized official; and
(e) the federal Business Number assigned to them by the Canada Revenue Agency, if any.

2 Information with respect to the covered facility:

(a) its name and the civic address of its physical location, if any;
(b) its latitude and longitude coordinates in decimal degrees or degrees, minutes and seconds, except for a covered facility referred to in paragraph (b) of the definition of facility in subsection 1(1) of these Regulations;
(c) its six-digit North American Industry Classification System (NAICS) Canada code;
(d) the covered facility certificate number that was issued to it;
(e) if applicable, the National Pollutant Release Inventory (NPRI) identification number assigned to it for the purposes of the Canadian Environmental Protection Act, 1999 and its Greenhouse Gas Reporting Program identification number; and
(f) in the case of an electricity generation facility or a covered facility referred to in paragraph 11(1)(c) that is composed, in part, of a unit or a group of units,
- (i) the unique name for each unit,
- (ii) the unit’s registration number under the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity, if any, and
- (iii) the unit’s registration number under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, if any.

3 The quantity of each GHG for the compliance period, expressed in tonnes, for each of the following emission types:

(a) stationary fuel combustion emissions;
(b) industrial process emissions;
(c) industrial product use emissions;
(d) venting emissions;
(e) flaring emissions;
(f) leakage emissions;
(g) on-site transportation emissions;
(h) waste emissions; and
(i) wastewater emissions.

4 The quantities of CH₄ and N₂O that are subtracted under subsection 17(5) or 20(6) of these Regulations from the total CH₄and N₂O, expressed in tonnes, separately.

5 A list of the methods used to calculate, sample, measure and analyze each specified emission type and GHG for the compliance period.

6 If a covered facility uses a continuous emissions monitoring system and has captured or stored CO₂, the quantity of CO₂ captured during the compliance period.

7 If CO₂ was captured, stored and deducted from the total quantity of GHGs under section 35 of these Regulations, the following information,

(a) a statement that indicates whether the CO₂ was stored in accordance with the requirements set out in subsection 35(2) of these Regulations;
(b) the type of geological storage site used, among those set out in paragraph 35(2)(a) of these Regulations;
(c) the latitude and longitude coordinates in decimal degrees or degrees, minutes and seconds, of the storage site; and
(d) the name and address of the owner or the operator of the storage site, if they are different than those of the person responsible for the covered facility.

8 The output-based standard for each of the specified industrial activities engaged in at the covered facility and, for a calculated output-based standard, the data used to calculate that standard.

9 The method used to determine the covered facility’s production from each of the specified industrial activities engaged in at the facility.

10 With respect to thermal energy that is sold or bought, in addition to the information required in section 12 of these Regulations:

(a) the name of each covered facility from which thermal energy was bought and the covered facility certificate number that was issued to it; and
(b) the name of each covered facility to which thermal energy was sold and the covered facility certificate number that was issued to it.

11 With respect to a facility that produces cement,

(a) in addition to the tonnes of grey cement, the tonnes of clinker, gypsum and limestone that the grey cement contains, separately; and
(b) in addition to the tonnes of white cement, the tonnes of clinker, gypsum and limestone that the white cement contains, separately.

12 With respect to a facility that produces petrochemicals, the quantity of hydrogen gas produced during the compliance period, in tonnes, the quantity of hydrogen gas sold, in tonnes, and the concentration of the hydrogen gas sold, expressed in weight percentage.

13 With respect to a facility that produces metal from the mining of ore

(a) in addition to the total quantity of silver, platinum and palladium, in kilograms, combined, each of those metals separately, and;
(b) in addition to the combined total of base metals, in tonnes combined, each of those base metals in ore concentrate, in tonnes, separately.

14 With respect to an electricity generation facility composed of a unit referred to in subsection 41(2) of these Regulations, a statement indicating whether solid fuel was used by the unit to generate electricity in 2018 and whether additional liquid or gaseous fuel was used in that same year, if that information is available.

15 With respect to a covered facility for which part or all of the electricity generated from fossil fuels is not quantified, a list of the units or equipment from which the electricity is generated but not quantified.

16 With respect to a covered facility referred to in section 36.2 or 41.2 of these Regulations, with respect to the units or equipment whose electricity generation capacity has been increased during a compliance period,

(a) the total capacity and thermal energy to electricity ratio of the unit or equipment prior to its capacity being increased;
(b) the total capacity and thermal energy to electricity ratio of the unit or equipment subsequent to its capacity being increased; and
(c) the date of completion of any modifications made to the unit or equipment to increase its capacity.

17 With respect to an electricity generation facility referred to in section 41.1 of these Regulations, the total capacity and thermal energy to electricity ratio of each unit within the facility that generates electricity from gaseous fuels.

SCHEDULE 3

(Subsections 17(2) to (4), and 20(2), (4) and (5), paragraphs 31(1)(a) and (b), 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	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	Directive 017 or Directive PNG017	GHGRP 2.D
2	Flaring emissions	CO₂, CH₄ and N₂O	WCI Method WCI.363(k)	Directive 017 or Directive PNG017	WCI Method WCI.365
3	Wastewater emissions from
	(a) anaerobic wastewater treatment	CH₄ and N₂O	WCI Method WCI.203(g)	WCI Method WCI.204(g)	WCI Method WCI.205
	(b) oil-water separators	CH₄	WCI Method WCI.203(h)	WCI Method WCI.204(h)	WCI Method WCI.205
4	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 2

Bitumen and Heavy Oil Upgrading

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	Directive 017 or Directive PNG017	GHGRP 2.D
2	Industrial process emissions from
	(a) hydrogen production	CO₂	WCI Method WCI.133	WCI Method WCI.134	WCI Method WCI.135
	(b) sulphur recovery	CO₂	WCI Method WCI.203(d)	WCI Method WCI.204(d)	WCI Method WCI.205
	(c) catalyst regeneration	CO₂, CH₄ and N₂O	WCI Method WCI.203(a)	WCI Method WCI.204(a)	WCI Method WCI.205
3	Flaring emissions	CO₂, CH₄ and N₂O	WCI Method WCI.203(e)	WCI Method WCI.204(e)	WCI Method WCI.205
4	Venting emissions from
	(a) process vents	CO₂ and N₂O	WCI Method WCI.203(b)	WCI Method WCI.204(b)	WCI Method WCI.205
	(b) uncontrolled blowdown	CO₂ and N₂O	WCI Method WCI.203(k)	WCI Method WCI.204(b)	WCI Method WCI.205
5	Wastewater emissions from
	(a) anaerobic wastewater treatment	CH₄ and N₂O	WCI Method WCI.203(g)	WCI Method WCI.204(g)	WCI Method WCI.205
	(b) oil-water separators	CH₄	WCI Method WCI.203(h)	WCI Method WCI.204(h)	WCI Method WCI.205
6	On-site transportation emissions	CO_2, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

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	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Venting emissions from
	(a) process vent	CO₂, CH₄ and N₂O	WCI Method WCI.203(b)	WCI Method WCI.204(b)	WCI Method WCI.205
	(b) asphalt production	CO₂, and CH₄	WCI Method WCI.203(c)	WCI Method WCI.204(c)	WCI Method WCI.205
	(c) delayed coking unit	CH₄	WCI Method WCI.203(m)	WCI Method WCI.204(m)	WCI Method WCI.205
3	Industrial process emissions from
	(a) hydrogen production	CO₂	WCI Method WCI.133	WCI Method WCI.134	WCI Method WCI.135
	(b) catalyst regeneration	CO₂, CH₄ and N₂O	WCI Method WCI.203(a)	WCI Method WCI.204(a)	WCI Method WCI.205
	(c) sulphur recovery	CO₂	WCI Method WCI.203(d)	WCI Method WCI.204(d)	WCI Method WCI.205
	(d) coke calcining	CO₂, CH₄ and N₂O	WCI Method WCI.203(j)	WCI Method WCI.204(i)	WCI Method WCI.205
4	Flaring emissions	CO₂, CH₄ and N₂O	WCI Method WCI.203(e)	WCI Method WCI.204(e)	WCI Method WCI.205
5	Leakage emissions	CH₄	WCI Method WCI.203(i)	WCI Method WCI.203(i)	WCI Method WCI.205
6	Wastewater emissions from
	(a) anaerobic wastewater treatment	CH₄ and N₂O	WCI Method WCI.203(g)	WCI Method WCI.204(g)	WCI Method WCI.205
	(b) oil-water separators	CH₄	WCI Method WCI.203(h)	WCI Method WCI.204(h)	WCI Method WCI.205
7	On-site transportation emissions	CO_2, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

DIVISION 2

Quantification of Production

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

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

(a) the value of “Sales and Exports of Steam and Electricity” must be set to zero;
(b) the value of “EC Reported CO₂e Site Emissions” excludes
- (i) the emissions associated with electricity generated at the covered facility, and
- (ii) the emissions associated with steam generated but not used by the covered facility;
(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
- (ii) is calculated using 0.420 tonnes of CO₂e per MWh of electricity bought;
(d) the value of “Deemed Indirect CO₂e Emissions from imported steam” is equal to 0; and
(e) the value of the “CWB factor” used to calculate hydrogen generation, in all cases, is 5.7.

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	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	Directive 017 or Directive PNG017	GHGRP 2.D
2	Industrial process emissions from acid gas removal	CO₂	WCI Method WCI.363 (c)	WCI Method WCI.364	WCI Method WCI.365
3	Flaring emissions	CO₂, CH₄ and N₂O	WCI Method WCI.363(k)	Directive 017 or Directive PNG017	WCI Method WCI.365
4	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

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	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Flaring emissions	CO₂, CH₄ and N₂O	WCI Method WCI.353(d)	Directive 017 or Directive PNG017	WCI Method WCI.355

DIVISION 2

Quantification of Production

1 (1) Production by the covered facility, expressed in MWh, 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 is the rated brake power of driver “x”, expressed in megawatts;

L 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_avgis the actual annual average speed during operation of driver “x”, expressed in revolutions per minute, and

rpm_maxis the maximum rated speed of driver “x”, expressed in revolutions per minute;

H 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	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions	CO₂	WCI Method WCI.133	WCI Method WCI.134	WCI Method WCI.135
3	Flaring emissions	CO₂, CH₄ and N₂O	WCI Method WCI.203(e)	WCI Method WCI.204(e)	WCI Method WCI.205
4	Leakage emissions	CH₄	WCI Method WCI.203(i)	WCI Method WCI.203(i)	WCI Method WCI.205
5	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

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	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions	CO₂	GHGRP 4.A	GHGRP 4.B	GHGRP 4.C
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

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	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions	CO₂	GHGRP 3.A	GHGRP 3.B	GHGRP 3.C
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

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	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions	CO₂	WCI Method WCI.143	WCI Method WCI.144	WCI Method WCI.145
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 10

Gypsum Product Manufacturing

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 11

Mineral Wool Insulation Manufacturing

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions	CO₂	WCI Method WCI.183	WCI Method WCI.184	WCI Method WCI.185
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 12

Brick Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions	CO₂	WCI Method WCI.183	WCI Method WCI.184	WCI Method WCI.185
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 13

Ethanol Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 14

Furnace Black Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in able 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions	CO₂	WCI Method WCI.303(b)	WCI Method WCI.304(b)	WCI Method WCI.305
3	Venting emissions	CO₂, CH₄ and N₂O	WCI Method WCI.303(a)(3)	WCI Method WCI.304(a)	WCI Method WCI.305
4	Leakage emissions	CH₄	WCI Method WCI.303(a)(4)	WCI Method WCI.304(a)	WCI Method WCI.305
5	Industrial product use emissions	SF₆ and PFCs	WCI Method WCI.233	WCI Method WCI.234	WCI Method WCI.235
6	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 15

2–methylpentamethylenediamine (MPMD) Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions	CO₂	WCI Method WCI.133	WCI Method WCI.134	WCI Method WCI.135
3	Industrial product use emissions	SF₆ and PFCs	WCI Method WCI.233	WCI Method WCI.234	WCI Method WCI.235
4	Flaring emissions	CO₂, CH₄ and N₂O	WCI Method WCI.203(e)	WCI Method WCI.204(e)	WCI Method WCI.205
5	Leakage emissions	CH₄	WCI Method WCI.203(i)	WCI Method WCI.203(i)	WCI Method WCI.205
6	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 16

Nylon Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ an 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 17

Petrochemicals Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions	CO₂	WCI Method WCI.303(b)	WCI Method WCI.304(b)	WCI Method WCI.305
3	Venting emissions	CO₂, CH₄ and N₂O	WCI Method WCI.303(a)(3)	WCI Method WCI.304(a)	WCI Method WCI.305
4	Flaring emissions	CO₂, CH₄ and N₂O	WCI Methods WCI.303(a)(1), (a)(2) and (c)	WCI Method WCI.304(a)	WCI Method WCI.305
5	Leakage emissions	CH₄	WCI Method WCI.303(a)(4)	WCI Method WCI.304(a)	WCI Method WCI.305
6	Wastewater emissions	CH₄ and N₂O	WCI Method WCI.203(g)	WCI Method WCI.204(g)	WCI Method WCI.205
7	Industrial product use emissions	SF₆ and PFCs	WCI Method WCI.233	WCI Method WCI.234	WCI Method WCI.235
8	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

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	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Leakage emissions	SF₆	WCI Method WCI.233	WCI Method WCI.234	WCI Method WCI.235
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

DIVISION 2

Quantification of Production

1 Production is quantified at the end of the formulation step of the manufacturing process, in litres of vaccine, as follows:

The summation of the products of Ai and Bi for each tank “i”

Detailed information can be found in the surrounding text.

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 ith tank where “i” goes from 1 to n where n is the total number tanks used to combine ingredients.

PART 19

Scrap-based Steel Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions from
	(a) electric arc furnace	CO₂	GHGRP 6.A.5	GHGRP 6.C.1	GHGRP 6.D
	(b) argon-oxygen decarburization vessel or vacuum degassing	CO₂	GHGRP 6.A.6	GHGRP 6.C.1	GHGRP 6.D
	(c) ladle furnace	CO₂	GHGRP 6.A.9	GHGRP 6.C.1	GHGRP 6.D
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 20

Integrated Steel Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial proces emissions from
	(a) basic oxygen furnace	CO₂	GHGRP 6.A.2	GHGRP 6.C.1	GHGRP 6.D
	(b) coke oven battery	CO₂	GHGRP 6.A.3	GHGRP 6.C.1	GHGRP 6.D
	(c) direct reduction furnace	CO₂	GHGRP 6.A.7	GHGRP 6.C.1	GHGRP 6.D
	(d) electric arc furnace	CO₂	GHGRP 6.A.5	GHGRP 6.C.1	GHGRP 6.D
	(e) blast furnace	CO₂	GHGRP 6.A.8	GHGRP 6.C.1	GHGRP 6.D
	(f) ladle furnace	CO₂	GHGRP 6.A.9	GHGRP 6.C.1	GHGRP 6.D
	(g) argon-oxygen decarburization vessel or vacuum degassing	CO₂	GHGRP 6.A.6	GHGRP 6.C.1	GHGRP 6.D
3	Wastewater emissions	CH₄ and N₂O	WCI Method WCI.203(g)	WCI Method WCI.204(g)	WCI Method WCI. 205
4	Industrial product use emissions	SF₆ and PFCs	WCI Method WCI.233	WCI Method WCI.234	WCI Method WCI. 235
5	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 21

Iron Ore Pelletizing

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions (induration furnace)	CO₂	GHGRP 6.A.1	GHGRP 6.C	GHGRP 6.D
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 22

Metal Tube Manufacturing

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 23

Base Metal Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄, and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions from
	(a) lead production	CO₂	WCI Method WCI.163	WCI Method WCI.164	WCI Method WCI.165
	(b) zinc production	CO₂	WCI Method WCI.243	WCI Method WCI.244	WCI Method WCI.245
	(c) copper and nickel production	CO₂	WCI Method WCI.263	WCI Method WCI.264	WCI Method WCI.265
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 24

Potash Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 25

Coal Mining

1 For the purpose of item 2 of Table 1 to this Part, the CH₄ leakage emissions from surface coal mining are quantified by multiplying the quantity of coal extracted by the applicable emission factor set out in column 3 of Table 2 to this Part according to the province of extraction set out in column 1 and the coal type set out in column 2 of Table 2.

**TABLE 1**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Leakage emissions from
	(a) coal storage	CH₄	WCI Method WCI.103	WCI Method WCI.104	WCI Method WCI.105
	(b) underground coal mining	CH₄	WCI Method WCI.253	WCI Method WCI.254	WCI Method WCI.255
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

**TABLE 2**
Item	Column 1 Province	Column 2 Coal Type	Column 3 Emission Factor (tonnes of CH₄/ tonnes of coal
1	Nova Scotia	Bituminous	7 x 10^–5
2	New Brunswick	Bituminous	7 x 10^–5
3	Saskatchewan	Lignite	7 x 10^–5
4	Alberta	Bituminous	5.5 x 10^–4
5	Alberta	Sub-bituminous	2 x 10^–4
6	British Columbia	Bituminous	8.6 x 10^–4

PART 26

Production of Metals or Diamonds

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c , 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 27

Char Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set outin Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 28

Activated Carbon Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 29

Nitrogen-based Fertilizer Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions from
	(a) nitric acid	N₂O	WCI Method WCI.313	WCI Method WCI.314	WCI Method WCI.315
	(b) ammonia steam reforming	CO₂	WCI Method WCI.83	WCI Method WCI.84	WCI Method WCI.85
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 30

Industrial Potato Processing

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Wastewater emissions	CH₄ and N₂O	WCI Method WCI.203(g)	WCI Method WCI.204(g)	WCI Method WCI.205
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 31

Industrial Oilseed Processing

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Wastewater emissions	CH₄ and N₂O	WCI Method WCI.203(g)	WCI Method WCI.204(g)	WCI Method WCI.205
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 32

Alcohol Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Wastewater emissions	CH₄ and N₂O	WCI Method WCI.203(g)	WCI Method WCI.204(g)	WCI Method WCI.205
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 33

Wet Corn Milling

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Wastewater emissions	CH₄ and N₂O	WCI Method WCI.203(g)	WCI Method WCI.204(g)	WCI Method WCI.205
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 34

Citric Acid Production

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 35

Sugar Refining

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in Table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

PART 36

Pulp and Paper Production

DIVISION 1

Quantification of Emissions

1 For the purposes of the table to this Division, GHGs from stationary fuel combustion emissions from biomass fuels may be quantified using equations 2-1, 2-2, 2-3, 2-7, 2-8, 2-9, 2-13, 2-14 or 2-18 of the GHGRP, if applicable.

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions from
	(a) boiler, thermal oxidizer, direct-fired turbine, engine, gasifier and any other combustion device that generates heat, steam or energy	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, (i) for biomass fuels, other than those set out in Table 2-3 and 2-11 of the GHGRP, use the emission factors provided in Table 20-2 of WCI Method WCI.20^{table c37 note a} (ii) for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
	(b) recovery boiler	CO₂, CH₄ and N₂O	For fossil fuels, GHGRP 2.A and 2.B, except for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O, and for pulping liquor, WCI Method WCI.213(c)^{table c37 note a}	For fossil fuels, GHGRP 2.C and for pulping liquor, WCI Method WCI.214	GHGRP 2.D and WCI Method WCI.215
	(c) lime kiln	CO₂	GHGRP 2.A	GHGRP 2.C	GHGRP 2.D
	(d) lime kiln	CH₄ and N₂O	GHGRP 2.B, except, (i) use the default emission factors for lime kilns set out in Table 210-1 of WCI Method WCI.213^{table c37 note a} (ii) for diesel, instead of the emission factors set out in Table 2-6 of 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial process emissions: addition of carbonate compound into a lime kiln	CO₂	WCI Method WCI.213(d)	Direct measurement of quantity of carbonate compounds used or indirect measurement using quantity of carbonate compounds according to the quantity on the delivery invoices	WCI Method WCI.215
3	Wastewater emissions	CH₄ and N₂O	WCI Method WCI.203(g)	WCI Method WCI.204(g)	WCI Method WCI.205
4	On-site transportation emissions	CO_2, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D
Table c37 note(s) Table c37 note a For the combustion of biomass fuels where CH₄ and N₂O emission factors are not prescribed, the IPCC Guidelines must be used to estimate those emissions. Return to table c37 note a referrer

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

Automotive Production

DIVISION 1

Quantification of Emissions

**QUANTIFICATION OF GHGS FROM CERTAIN SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Stationary fuel combustion emissions	CO₂, CH₄ and N₂O	GHGRP 2.A and 2.B, except, for diesel, instead of the emission factors set out in table 2-6 of section 2.B, use 0.133 kg/kL for CH₄ and 0.4 kg/kL for N₂O	GHGRP 2.C	GHGRP 2.D
2	Industrial product use emissions	HFCs	WCI Method WCI.43(d)	WCI Method WCI.44	WCI Method WCI.45
3	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

DIVISION 2

Quantification of Production

1 Production is the number of four-wheeled self-propelled vehicles that are designed for use on a highway and that have a gross vehicle weight rating of less than 4 536 kg (10,000 pounds) assembled during a compliance period.

PART 38

Electricity Generation

DIVISION 1

Quantification of Emissions

Stationary Fuel Combustion Emissions

1 (1) CO₂, CH₄ and N₂O from stationary fuel combustion emissions must be quantified by unit in accordance with the following:

(a) for CO₂,
- (i) in the case of any unit that has obtained a registration number under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, sections 20 to 26 of those Regulations,
- (ii) in the case of any unit that has not obtained a registration number under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations and that generates electricity from the combustion of natural gas, sections 12 to 18 of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity, and
- (iii) in the case of any other unit, GHGRP 2.A; and
(b) for CH₄ and N₂O, in the case of all units, GHGRP 2.B.

(2) For the purposes of paragraph (1)(b), for the stationary combustion of diesel, the following emission factors must be used instead of those set out in Table 2-6 to section 2.B of the GHGRP:

(a) for CH₄, 0.133 kg/kL; and
(b) for N₂O, 0.4 kg/kL.

2 The following sampling, analysis and measurement requirements apply to stationary fuel combustion emissions for each unit:

(a) for CO_2,
- (i) in the case of any unit that has obtained a registration number under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, section 27 of those Regulations,
- (ii) in the case of any unit that has not obtained a registration number under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations and that generates electricity from the combustion of natural gas, section 19 of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity, and
- (iii) in the case of any other unit, GHGRP 2.C; and
(b) for CH₄ and N₂O, in the case of all units, GHGRP 2.C.

3 Replacement data for stationary fuel combustion emissions must be calculated for each unit in accordance with the following:

(a) for CO_2,
- (i) in the case of any unit that has obtained a registration number under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, section 28 of those Regulations,
- (ii) in the case of any unit that has not obtained a registration number under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations and that generates electricity from the combustion of natural gas, section 20 of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity, and
- (iii) in the case of any other unit, GHGRP 2.D; and
(b) for CH₄ and N₂O, in the case of all units, GHGRP 2.D.

Emissions from Other Specified Emission Types

**QUANTIFICATION OF GHGS FROM OTHER SPECIFIED EMISSION TYPES**
Item	Column 1 Specified Emission Types	Column 2 GHGs	Column 3 Method for Calculating GHGs	Column 4 Sampling, Analysis and Measurement Requirements	Column 5 Method for Estimating Missing Analytical Data
1	Leakage emissions from coal storage	CH₄	WCI Method WCI.103	WCI Method WCI.104	WCI Method WCI.105
2	Industrial process emissions from acid gas scrubbers and acid gas reagent	CO₂	WCI Method WCI.43(c)	WCI Method WCI.44	WCI Method WCI.45
3	Industrial product use emissions from
	(a) electrical equipment	SF₆ and PFCs	WCI Method WCI.233	WCI Method WCI.234	WCI Method WCI.235
	(b) cooling units	HFCs	WCI Method WCI.43(d)	WCI Method WCI.44	WCI Method WCI.45
4	On-site transportation emissions	CO₂, CH₄ and N₂O	GHGRP 2.A.1.c, 2.A.1.d, 2.A.2.e and 2.B	GHGRP 2.C	GHGRP 2.D

DIVISION 2

Quantification of Production — Main Industrial Activity

4 (1) Subject to section 5, if a unit uses only one fossil fuel to generate electricity, production of electricity must be quantified in GWh 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 of the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations.

(2) Subject to section 5, 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 GWh:

where

G_Uis 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 of the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations, expressed in GWh;

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

where

QFF_jis 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_jis 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 subsection 24(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, 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

H_Bis determined in accordance with the formula

where:

QB_iis 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_iis the higher heating value for the biomass fuel type “i” combusted in the unit, is determined in accordance with subsection 24(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, 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.

5 If a combustion engine unit and a boiler unit share the same steam turbine, the quantity of electricity generated by a given unit is determined in accordance with subsection 11(2) of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity.

DIVISION 3

Additional Industrial Activity – Quantification of Production

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

7 (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 GWh:

where

G_Uis the gross quantity of electricity generated by the covered facility during the compliance period, expressed in GWh;

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

where

QFF_jis 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 section 2.C.2 of the GHGRP 2.C.2,

HHV_jis 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 sections 2.C.1 and 2.C.3 of the GHGRP, 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

H_Bis determined in accordance with the formula

where

QB_iis 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 section 2.C.2 of the GHGRP and the WCI Method WCI.214,

HHV_iis the higher heating value for each biomass fuel type “i” combusted in the facility for electricity generation in accordance with sections 2.C.1 and 2.C.3. of the GHGRP and the WCI Method WCI.214, 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 section 2.C.2 of the GHGRP;
(b) for a liquid fuel, the volume of the fuel combusted, expressed in kL and measured in accordance with section 2.C.2. of the GHGRP; and
(c) for a gaseous fuel, the volume of the fuel combusted, expressed in standard cubic metres and measured in accordance with section 2.C.2 of the GHGRP 2.C.2.

SCHEDULE 4

(Subsections 27(1) and 29(1))

Information to Include in Application for Permit

1 Information with respect to the applicant:

(a) their name, civic and postal addresses in Canada, telephone number and, if any, email address; and
(b) the name, title, civic and postal addresses in Canada, telephone number and, if any, email address of their authorized official.

2 The covered facility certificate number that was issued to the covered facility for which the application is being submitted.

3 Details with respect to

(a) each prescribed method or guideline that cannot be used;
(b) the specified emission type and GHG; and
(c) the requirement that cannot be met.

4 Information establishing that, at the time of the application, it is not technically or economically feasible for the applicant to use the prescribed quantification method or guideline.

5 A description of the alternative method to be used for each method or guideline in respect of which a permit is sought and information that demonstrates that the quantification method being proposed is at least as rigorous as the prescribed method or guideline and provides equivalent results to those that would have been obtained from the prescribed method or guideline.

6 The requested term of the permit, which must be the period for which the permit is necessary.

SCHEDULE 5

(Section 52 and subsection 53(1)(b))

Content of Verification Report

1 Information with respect to the person responsible for a covered facility:

(a) an indication as to whether they own or are otherwise responsible for the covered facility, including having the charge, management or control of the facility, or are the true decision maker with respect to the facility’s operations;
(b) their name (including any trade name or other name used by them) and civic address;
(c) the name, title, civic and postal addresses, telephone number and, if any, email address of their authorized official;
(d) the name, title, civic and postal addresses, telephone number and, if any, email address of a contact person, if different from the authorized official; and
(e) the federal Business Number assigned to them by the Canada Revenue Agency, if any.

2 Information with respect to the covered facility:

(a) its facility name and the civic address of its physical location, if any;
(b) its latitude and longitude coordinates in decimal degrees or degrees, minutes and seconds, except for a covered facility referred to in paragraph (b) of the definition of facility in subsection 1(1) of these Regulations;
(c) its six-digit North American Industry Classification System (NAICS) Canada code;
(c.1) the covered facility certificate number that was issued to it;
(d) if applicable, the National Pollutant Release Inventory (NPRI) identification number assigned to it for the purposes of the Canadian Environmental Protection Act, 1999 and its Greenhouse Gas Reporting Program identification number; and
(e) in the case of an electricity generation facility or a covered facility referred to in paragraph 11(1)(c) that is composed, in part, of a unit or a group of units,
- (i) the unique name for each unit,
- (ii) the unit’s registration number under the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity, if any, and
- (iii) the unit’s registration number under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, if any.

3 Information with respect to the verification:

(a) the name and civic address of the verification body, as well as the name, telephone number and email address of the lead verifier for the team that conducted the verification;
(b) the name and contact information of the accreditation organization by which the verification body is accredited and the date of the verification body’s accreditation;
(c) the names and functions of each member of the verification team;
(d) the version of the ISO Standard 14064-3 according to which the verification was conducted and a description of the objectives and scope of the verification and the verification criteria;
(e) a summary of the verification procedures conducted on the data and information supporting an annual report or a corrected report, including
- (i) any assessments, data sampling, tests and reviews that were conducted during the verification,
- (ii) any tests of the GHG information system and controls, and
- (iii) the date of each visit conducted, for the purpose of section 51 of these Regulations;
(f) the total quantity of GHGs from a covered facility, other than a facility referred to in paragraph (g) or (h), during the compliance period and the production from each specified industrial activity during the compliance period that is used in the calculation of the emissions limit by the covered facility, as described in the annual report or corrected report, as the case may be, for the covered facility;
(f.1) if section 36.2 of these Regulations applies to a covered facility, the electricity generation attributed to the capacity added to the equipment and the electricity generation attributed to the capacity of the equipment before the additional capacity was added, as described in the annual report or corrected report, as the case may be;
(g) in the case of a verification of an electricity generation facility, the following information as described in its annual report or corrected report, as the case may be:
- (i) the total GHGs from each unit within the electricity generation facility and the sum of the total GHGs from each unit within the facility during the compliance period, and
- (ii) the production during the compliance period by each unit within the electricity generation facility for each of the industrial activities set out in paragraphs 38(a) to (c), column 1, of Schedule 1 and the sum of the production from all units within the electricity generation facility;
(h) in the case of a covered facility, where the specified industrial activities are both the production of coal by mining coal deposits and, if composed of a unit or a group of units that are registered under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, the generation of electricity, as described in its annual report or corrected report, as the case may be,
- (i) the total quantity of GHGs from the covered facility during the compliance period, expressed in CO₂e tonnes,
- (ii) with respect to the production of coal by mining coal deposits, the production from each specified industrial activity during the compliance period that is used in the calculation of the emissions limit, and
- (iii) with respect to the generation of electricity, the production during the compliance period by each unit within the electricity generation facility for each of the industrial activities set out in paragraphs 38(a) to (c), column 1, of Schedule 1 and the sum of the production from all units within the electricity generation facility;
(h.1) if section 41.2 of these Regulations applies to an electricity generation facility or a covered facility referred to in paragraph (h), the electricity generated that is attributed to the capacity added to each unit as described in its annual report or corrected report, as the case may be:
- (i) for each unit whose electricity generation capacity from gaseous fuels was increased by 50 MW or more and has a thermal energy to electricity ratio of less than 0.9, separately, the gross amount of electricity generated during the compliance period by each unit that is attributed to the capacity added to the unit and the gross amount of electricity generated that is attributed to capacity of the unit before the additional capacity was added, and
- (ii) the sum, from all of the units referred to in subparagraph (i), of gross amount of electricity generated that is attributed to the capacity added to the units and of the electricity generated attributed to the capacity of the units before the additional capacity was added, separately;
(i) in the case of a covered facility that calculated an output-based standard in accordance with section 37 of these Regulations, the calculated output-based standard and the information associated with each term in the equation;
(j) a record of errors or omissions capable of influencing the assessment of the quantity of GHGs that are emitted from a covered facility during the applicable compliance period against its applicable GHG emissions limit, identified during the verification, in the data, information or methods used in the preparation of the annual report or corrected report, as the case may be, that indicates,
- (i) with respect to each error and omission, if it may be quantified,
- (ii) with respect to the aggregate of the errors or omissions in relation to GHG emissions, that may be quantified, the net result of the errors and omissions expressed in CO₂e tonnes, the related percentage calculated in accordance with subparagraph 49(2)(a)(ii), (b)(ii) or (c)(ii) of these Regulations and a statement indicating whether the net result is an understatement or an overstatement;
(k) a record of any corrections made by the person responsible as a result of any errors or omissions capable of influencing the assessment of the quantity of GHGs that are emitted from a covered facility during the applicable compliance period against its applicable GHG emissions limit, identified during the verification;
(l) a declaration, signed and dated by the lead verifier, stating that the requirements of section 50 of these Regulations have been complied with and that any real or potential conflicts of interest have been effectively managed;
(m) a declaration, signed and dated by a reviewer who is not a member of the verification team, stating their approval of the verification report, including the name, civic address, telephone number and email address of that reviewer; and
(n) a verification statement by the verification body containing
- (i) determinations as to whether a material discrepancy exists with respect to the total quantity of GHGs and the total production from each specified industrial activity used in the calculation of the emissions limit in the annual report or corrected report, as the case may be, and whether the annual report or corrected report was prepared in accordance with these Regulations, and
- (ii) any qualifications or limitations the verification body has related to those determinations.

SCHEDULE

(Section 92)

SCHEDULE 5

(Section 5, subsection 6(1) and section 8.1)

Penalty Amounts
Item	Column 1 Violator	Column 2 Violation Type	Column 3 Baseline Penalty Amount ($)	Column 4 History of Non-compliance Amount ($)	Column 5 Economic Gains Amount ($)
1	Individual
		(a) D	400	1,200	400
		(b) E	1,000	3,000	1,000
2	Other person
		(a) D	2,000	6,000	2,000
		(b) E	5,000	15,000	5,000

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations or the Order.)

Executive summary

Issues: Greenhouse gas (GHG) emissions are contributing to a global warming trend that is associated with climate change, which will lead to changes in average climate conditions and extreme weather events. ^{footnote 2} It is widely recognized that economy-wide carbon pollution pricing is the most efficient way to reduce GHG emissions. However, not all jurisdictions around the world are putting an equivalent price on carbon pollution. This creates a risk for industrial facilities that are emissions-intensive and that compete in international markets. If these Canadian facilities face costs on their GHG emissions that their international competitors do not, they may lose market share to facilities in other jurisdictions with lower carbon-related costs.

This can result in a phenomenon known as carbon leakage, in which production is simply displaced to another location, with domestic GHG emissions “leaking” out of Canada to other jurisdictions. Without appropriate measures for industrial facilities, it is also likely that competitiveness impacts and carbon leakage leading to domestic production losses could lead to corresponding impacts on the welfare of Canadian households.

Description: Part 2 of the Greenhouse Gas Pollution Pricing Act provides the legal framework and authorities to establish a regulatory trading system for industrial facilities — the Output-Based Pricing System (OBPS) — that will be administered by the Department of the Environment (the Department) and the Canada Revenue Agency under the Output-Based Pricing System Regulations (the Regulations). Facilities subject to the OBPS will generally not pay the carbon pollution price on fuel they purchase for use at their covered facility. Instead, under the OBPS, participants are required to compensate for GHG emissions that exceed an annual facility emissions limit. The Minister of the Environment will issue surplus credits to facilities that emit GHGs in a quantity that is below their limit. These surplus credits can be sold to facilities that need credits for compliance or banked for future use. This creates an ongoing financial incentive for facilities to reduce their emission intensity in order to reduce the amount owed for compensation or to emit below their limit and earn surplus credits.

Rationale: The objective of the Regulations is to retain a price on carbon pollution that creates an incentive for emissions-intensive and trade-exposed facilities to reduce emissions per unit of output, while mitigating the risk of decreased domestic production and of carbon leakage to other jurisdictions. The system provides flexibility in how compensation is provided in order to incent lowest cost GHG emission reductions.

The cost-benefit analysis compares the impact of applying the OBPS (the Regulatory Scenario) versus applying the fuel charge to all industrial fuel use (the Baseline Scenario) in backstop jurisdictions. The OBPS and the fuel charge create comparable incentives to reduce emissions intensity. However, by imposing a smaller total cost, the OBPS results in higher domestic production. This in turn increases household income, allowing households to increase their consumption to maximize welfare. Increased domestic production also results in slightly more domestic GHG emissions than would have occurred under the fuel charge only scenario. These GHG emissions are expected to be offset by a reduced risk of Canadian production shifting to other jurisdictions and creating carbon leakage, but the analysis is unable to quantify the reduced carbon leakage. Therefore, the results of the analysis likely overestimate total foregone GHG emission reductions.

By 2030, when compared to the Baseline Scenario, the Regulations are estimated to result in an increase in household welfare valued at $3.2 billion. Cumulative foregone domestic GHG emissions reductions are estimated to amount to 22 Mt CO₂e, valued at $916 million. The cumulative administrative and verification costs of the OBPS are estimated to be $155 million. The monetized net benefits of the Regulations to Canadians are estimated to be $2.15 billion. The costs and benefits associated with the Regulations are summarized in Table 8.

Since 2017, the Department has engaged with industry, provinces and territories, environmental non-governmental organizations, organizations of Indigenous peoples and the general public to explain and receive feedback on the design of the OBPS. The federal government published various documents in order to engage with and keep stakeholders up to date on various aspects of the process. For example, the government published a Notice of Intent, regulatory instruments, a regulatory proposal for the OBPS Regulations, a cost-benefit analysis framework, a policy on voluntary participation, and other guidance documents.

Issues

Greenhouse gas (GHG) emissions are contributing to a global warming trend that is associated with climate change, which will lead to changes in average climate conditions and extreme weather events. Science confirms that the impacts of climate change will worsen as the global average surface temperature becomes increasingly warmer. Canada’s climate is warming at twice the global rate and, in the North, at three times that rate. If no action is taken on climate change, the severity of impacts already being felt in Canada (e.g. floods, fires, heat waves and droughts) will increase. ^{footnote 3}

Recognizing the need for climate action, the Government of Canada, provinces, and territories developed and adopted the Pan-Canadian Framework on Clean Growth and Climate Change (PCF) in 2016 — Canada’s climate plan to reduce its GHG emissions by 30% below 2005 levels by 2030 ^{footnote 4}. Pricing carbon pollution is a key pillar of this climate plan. It is widely recognized that economy-wide carbon pollution pricing is the most efficient way to reduce GHG emissions. Pricing carbon pollution ensures emissions are reduced at the lowest cost, while driving innovative solutions to provide low-carbon choices for consumers and businesses.

Not all jurisdictions around the world are putting an equivalent price on carbon pollution and this creates a risk for industrial facilities that are emissions-intensive and that compete in international markets. If these Canadian facilities face costs on their GHG emissions that their international competitors do not, they may lose market share to facilities in other jurisdictions with lower carbon-related costs. This can result in a phenomenon known as carbon leakage, in which production is simply displaced to another location, with domestic GHG emissions “leaking” out of Canada to other jurisdictions. If this happens, global GHG emissions may not decrease, undermining the purpose of the carbon pollution pricing policy. Without appropriate measures for industrial facilities, it is likely that competitiveness impacts and carbon leakage leading to domestic production losses could lead to corresponding impacts on the welfare of Canadian households.

Background

Under the Paris Agreement, adopted by the international community in December 2015 and ratified by Canada on October 5, 2016, countries committed to reducing GHG emissions to limit the rise in global average temperature to less than two degrees Celsius (2 °C) above preindustrial levels, and to pursue efforts to limit the increase to 1.5 °C. ^{footnote 5}

In 2016, the Government of Canada worked with provinces and territories and engaged with Indigenous peoples to develop the PCF. A key pillar of Canada’s climate plan includes putting a price on carbon pollution that applies to a broad set of emission sources across Canada with increasing stringency over time.

Under this approach, provinces and territories had the flexibility to implement the type of carbon pollution pricing system that makes sense for their circumstances, either an explicit price-based system or a cap-and-trade system, as long as they meet minimum criteria to ensure they are stringent, fair, and efficient (these criteria are referred to as the federal Benchmark). The federal government also committed to implementing a federal carbon pollution pricing system as a backstop in any province or territory that requests it or that does not implement a carbon pollution pricing system that meets the federal Benchmark. ^{footnote 6}

The Greenhouse Gas Pollution Pricing Act (GGPPA) received royal assent on June 21, 2018. ^{footnote 7} It provides the legal framework and enabling authorities for the federal backstop carbon pollution pricing system. This system has two parts: a regulatory charge on fossil fuels (the fuel charge), and the Output-Based Pricing System (OBPS) for industrial facilities.

Part 1 of the GGPPA establishes the fuel charge, which is generally paid by fuel producers or distributors and generally applies to fossil fuels produced, delivered, or used in a backstop jurisdiction, brought into a backstop jurisdiction from another place in Canada, or imported into Canada at a location in a backstop jurisdiction. The federal fuel charge came into force on April 1, 2019, in Ontario, New Brunswick, Manitoba, and Saskatchewan, and will come into force on July 1, 2019 in Yukon and Nunavut. The fuel charge is being implemented by the Canada Revenue Agency (CRA). Part 2 of the GGPPA provides the legal framework and authorities to establish a regulatory trading system for industrial facilities — the OBPS — that will be administered by the Department of the Environment (the Department) and CRA under the Output-Based Pricing System Regulations (the Regulations). Facilities subject to the OBPS will generally not pay the carbon pollution price on fuel they purchase for use at their covered facility, and instead will pay the carbon pollution price on their GHG emissions that exceed their limit.

The GGPPA provides the Governor in Council with authority to determine where the GGPPA applies by listing provinces and territories in Schedule 1 of the GGPPA through an Order in Council. The primary consideration in making the decision to list a jurisdiction is the stringency of the provincial or territorial carbon pollution pricing system, and alignment with the federal Benchmark.

Provinces and territories submitted their carbon pollution pricing plans to the Minister of the Environment (the Minister) in fall 2018. These plans were then assessed against the federal Benchmark. The Order Amending Part 2 of Schedule 1 to the Greenhouse Gas Pollution Pricing Act (the Order) was published on October 19, 2018. ^{footnote 8} The Order identified the jurisdictions in which Part 2 of the GGPPA (the OBPS) applies by adding the following provinces and territories to Part 2 of Schedule 1 to the GGPPA as “backstop jurisdictions”:

Ontario
New Brunswick
Manitoba
Prince Edward Island
Saskatchewan
Yukon
Nunavut

Two additional regulatory instruments were also published in the Canada Gazette, Part II, on October 31, 2018, in order to allow the OBPS to take effect January 1, 2019, prior to the final publication of the Regulations. ^{footnote 9}

Facilities meeting criteria set out in the Notice Establishing Criteria Respecting Facilities and Persons and Publishing Measures (Registration Notice) are considered covered facilities under Part 2 of the GGPPA, and the persons responsible for covered facilities are required to apply for registration of the facility in the OBPS. ^{footnote 10} Upon registration, the facility obtains a covered facility certificate enabling it to register as an emitter with CRA and obtain an exemption certificate that generally allows them to purchase fuel to which the fuel charge was not applied.
The Greenhouse Gas Emissions Information Production Order (Information Order) set out quantification, reporting, and verification requirements to ensure OBPS facilities begin collecting the necessary information starting on January 1, 2019 (July 1, 2019 in Yukon and Nunavut), that will be required to assess compliance under the OBPS. ^{footnote 11}

The Department also published a notice of intent on December 20, 2018, that allows the Regulations to take effect on January 1, 2019, except in Yukon and Nunavut where they take effect July 1, 2019, prior to the publication of the Regulations. ^{footnote 12}

Emissions-intensive and trade-exposed sectors in backstop jurisdictions

The OBPS provides relief from the fuel charge to emission-intensive and trade-exposed (EITE) facilities that carry out an activity listed in Column 1 of Schedule 1 of the Regulations. The listed activities were determined by identifying the industrial sectors in which at least one facility had reported to the Greenhouse Gas Reporting Program (GHGRP) ^{footnote 13} 50 kilotonnes (kt) or more of carbon dioxide equivalent (CO₂e) emissions in any year from 2014 to 2016 in jurisdictions that did not have carbon pollution pricing. Table 1 below outlines the sectors and products/activities that are covered by the OBPS.

**Table 1: Sectors and products/activities covered by the OBPS**
Sector	Product/Activity
Oil and gas	Oil production — light oil; Oil production — heavy oil; Bitumen upgrading; Petroleum refineries; Lubricant refineries; Isopropyl alcohol; Natural gas pipelines; Natural gas processing; Natural gas liquids; Hydrogen
Cement	Grey cement; white cement; Clinker sent off site
Lime	High calcium; Dolomitic; Specialty
Light manufacturing	Brick; Automotive; Glass; Gypsum; Mineral wool
Ethanol	Fuel; Industrial
2-methylpenta-methylenediamine (MPMD)	MPMD
Nylon 6 or 6,6	Nylon 6 or 6,6 Fibers or Resins
Petrochemicals	High value chemicals; Aromatic cyclic hydrocarbons (HCs); Polyethylene; Higher olefins; HC solvents; Styrene
Pharmaceuticals	Vaccines
Iron and steel mini mills	Cast steel; Rolled steel
Iron and steel integrated steel	Coke; Iron; Basic oxygen furnace (BOF) steel; Electric Arc Furnace (EAF) steel
Base metal smelting (BMS)	Pyrometallurgical smelting of • Copper; lead; zinc; nickel Hydrometallurgical refining of • Base metals; copper anodes
Potash	Solution mining; Conventional underground mining
Mining	Iron ore; Base metal (excluding iron, precious metals, uranium); Uranium; Gold; Other precious metals; Diamonds; Thermal coal; Metallurgical coal
Iron ore pellets	Flux pellets; pellets other than flux pellets
Metal tubes	Metal tubes
Char	Char
Activated carbon	Activated carbon
Carbon black	Furnace black
Nitrogen fertilizers	Nitric acid; Ammonia; Urea liquor; Ammonium phosphate
Food processing	Potato processing; Oilseed processing; Wet corn milling; Alcohol (distilleries); Citric acid; Sugar
Pulp and paper	(a) At a facility equipped with a recovery boiler, lime kiln or pulping digester (b) At a facility not equipped with equipment in (a) (c) Specialty papers
Fossil fuel electricity	Solid fuel; Liquid fuel; Gas fuel

There are 122 facilities in backstop jurisdictions that meet the criteria in the Registration Notice and are registered with the OBPS as mandatory facilities. There are 15 mandatory facilities in Saskatchewan, 7 in Manitoba, 86 in Ontario, 10 in New Brunswick, 1 in Prince Edward Island, and 3 in Nunavut.

Table 2 below shows the share of total GHG emissions captured under the two federal systems (fuel charge and the OBPS, making up the GGPPA). It is estimated that, in 2019, approximately 27% of Canada’s emissions will be covered by the federal backstop carbon pollution pricing system, with approximately 16% of Canada’s total emissions covered by the fuel charge (Part 1 of the GGPPA) and 10% emitted by facilities covered by the OBPS (Part 2 of the GGPPA). ^{footnote 14}

**Table 2: Share of 2019 GHG emissions covered by the backstop carbon pollution pricing system**
Backstop jurisdictions	Covered by Fuel Charge (%)	Covered by OBPS (%)	Covered by the GGPPA (%)
Manitoba	43%	10%	54%
New Brunswick	31%	54%	85%
Nunavut	17%	59%	76%
Ontario	53%	29%	82%
Prince Edward Island ^{table 2 note *}	Not applicable	4%	4%
Saskatchewan ^{table 2 note **}	20%	22%	42%
Yukon	71%	12%	83%
All backstop jurisdictions	42%	27%	69%
Canada	16%	10%	27%
Table 2 note(s) Table 2 note * Instead of the federal fuel charge, a provincial levy applies in Prince Edward Island. Return to table 2 note * referrer Table 2 note The OBPS only applies to the natural gas transmission pipelines and electricity sectors. The Saskatchewan system applies to other industrial sectors in the province. Return to table 2 note referrer

Note: Numbers may not add up due to rounding and are based on all facilities covered by the OBPS.^{footnote 15}

Approaches to pricing industrial GHG emissions in Canada

Carbon pollution pricing systems in Canada have taken different approaches to pricing industrial GHG emissions. As of April 1, 2019, the federal fuel charge applies in Ontario, New Brunswick, Manitoba, and Saskatchewan. The OBPS took effect starting on January 1, 2019, in Ontario, New Brunswick, Manitoba, Prince Edward Island, and for two sectors in Saskatchewan (electricity and natural gas transmission pipelines). Saskatchewan is implementing its own output-based pricing system that applies to other sectors not covered by the federal OBPS. To account for the unique circumstances of the territories, both parts of the federal backstop will start applying on July 1, 2019, in Yukon and Nunavut.

Nova Scotia has a cap-and-trade system that applies to industrial facilities and Newfoundland and Labrador has a performance-based system for industrial facilities. In 2007, Alberta implemented its Specified Gas Emitters Regulation (SGER), which set facility-specific emission-intensity targets for large industrial facilities. In 2018, this regulation was replaced with the Carbon Competitiveness Incentive Regulation (CCIR), which sets output-based benchmarks for products produced by industrial facilities. ^{footnote 16}

British Columbia’s broad-based carbon tax applies to fuels purchased across the economy, including by industrial facilities. British Columbia recently announced its intention to provide support to industrial facilities to address carbon leakage concerns. Quebec’s cap-and-trade system applies to large industrial emitters and fuel distributors and includes free allocation of permits to some sectors to address carbon leakage risks.

Various approaches to pricing industrial GHG emissions internationally

Globally, 57 carbon pricing initiatives are implemented or scheduled to be implemented, covering 46 national jurisdictions and 28 subnational jurisdictions. ^{footnote 17} International systems of particular relevance to Canada, both as models and as trading partners, are the European Union’s Emissions Trading System (EU ETS) and California’s cap-and-trade system.

The EU ETS was the first large-scale GHG emissions cap-and-trade system in the world. In this system, a declining cap was set to limit the amount of GHGs industrial facilities could emit in order to reduce GHG emissions across the EU. The system includes the ability for industrial facilities to meet their compliance obligations through the trading of credits with other industrial facilities within the system.

The State of California adopted a cap-and-trade system in 2013. The system applies to large electric power plants, industrial facilities, and fuel distributors responsible for approximately 85% of California’s GHG emissions. This system is linked with Quebec’s cap-and-trade program, allowing businesses to trade allowances across both jurisdictions.

Both of these systems have addressed issues related to competitiveness and carbon leakage by assessing metrics such as trade exposure and emissions intensity, and providing free allocations to sectors at higher risk.

Although more countries and subnational jurisdictions are implementing or considering carbon pricing, carbon leakage remains a risk.

Objective

The objective of the Regulations is to retain a price on carbon pollution that creates an incentive for EITE facilities to reduce emissions per unit of output, while mitigating the risk of decreased domestic production and of carbon leakage to other jurisdictions. The system provides flexibility in how compensation is provided in order to incent lowest cost GHG emission reductions.

Description

The Regulations describe the facilities to which the OBPS applies and specify the emission intensity standards, referred to as output-based standards, for specific activities. They also provide the monitoring, quantification, reporting, and verification requirements and rules related to the compensation for excess emissions and issuance of surplus credits. All obligations under the Regulations are on the person responsible for the covered facility.

Under the OBPS, participants are required to compensate for GHG emissions that exceed an annual facility emissions limit. The Minister will issue surplus credits to facilities that emit GHGs in a quantity that is below their limit. These surplus credits can be sold to facilities that need credits for compliance or banked for future use. Facilities that exceed their limit will be required to provide compensation for the emissions exceeding their limit. This creates an ongoing financial incentive for facilities to reduce their emission intensity in order to reduce the amount owed for compensation or to emit below their limit and earn surplus credits.

Mandatory participants

The federal OBPS is mandatory for facilities that are located in a backstop jurisdiction and that:

Have reported annual emissions of 50 kt of CO₂e or more to the GHGRP, for the 2014 calendar year or any calendar year thereafter; and
Carry out an activity listed in Schedule 1 of the Regulations as its primary activity. ^{footnote 18}

The facilities that meet these criteria are required to apply for registration of their facility and participate in the OBPS (hereafter referred to as “mandatory participants”). The activities listed in Schedule 1 of the Regulations are in sectors in jurisdictions that did not have carbon pricing in place in 2018 and for which at least one facility reported to the GHGRP emissions amounting to 50 kt of CO₂e or more in any year from 2014 to 2016.

To allow for registration of covered facilities ahead of the implementation of the fuel charge, the Registration Notice (published on October 31, 2018) listed the criteria for mandatory participants. These criteria were incorporated, with small improvements, to the Regulations to allow for ongoing registration of facilities. Now that the content of the Registration Notice is integrated in the Regulations, it is no longer necessary. The Minister is therefore making the Order Repealing Certain Legislative Instruments to repeal the Registration Notice.

Voluntary participants

The GGPPA enables the Minister to designate additional facilities in backstop jurisdictions as covered facilities if they choose to voluntarily participate in the OBPS (opt-in). The Policy regarding voluntary participation in the output-based pricing system (Voluntary Participation Policy) identifies the considerations that guide the Minister’s decision, on a case-by-case basis, to designate a facility as a covered facility. ^{footnote 19} Under the policy, the Minister will consider the opt-in application of facilities located in backstop jurisdictions with reported annual emissions to the GHGRP for any year (starting with the 2017 reporting year) of at least 10 kt of CO₂e, as long as their primary activity is listed in Schedule 1 of the Regulations.

The Voluntary Participation Policy also enables facilities not carrying out a listed activity to apply to opt into the OBPS, provided that they are in sectors that are at significant risk of carbon leakage and competitiveness impacts. The current list of these sectors is provided in Appendix A of the Voluntary Participation Policy. Other sectors will be added to Appendix A if it is demonstrated that the sector meets the criteria of being at significant risk of carbon leakage and competitiveness impacts from carbon pollution pricing. Facilities applying under this part of the Voluntary Participation Policy must provide sufficient information with their application to enable an output-based standard to be set for the facility.

Finally, the Voluntary Participation Policy enables recently commissioned, expanded, and retrofitted facilities in backstop jurisdictions whose emissions have not yet exceeded 10 kt of CO₂e to apply to opt-in to the OBPS if the facility demonstrates that its emissions will exceed 10 kt of CO₂e within three years of the date of commissioning.

Annual facility emissions limits

The annual facility emissions limit (measured in tonnes of CO₂e) will be determined by multiplying the facility’s production by the applicable output-based standard. The output-based standard is generally set at 80% of the national, production-weighted average emissions intensity of a specific activity. Some output-based standards were adjusted from 80% based on an assessment of the potential competitiveness and carbon leakage risks due to carbon pricing. These adjustments included sectors with an average proportion of industrial process emissions of 30% or greater. Table 3 below outlines the sectors and activities with an assigned output-based standard and their stringency levels.

**Table 3: Sectors/activities and assigned stringency levels in the OBPS**
Stringency	Sector (bolded)/Activity
95%	Nitrogen fertilizers - nitric acid, ammonia Iron & steel - mini mills cast steel, mini mills rolled steel, integrated steel-coke, integrated steel-iron, integrated steel-BOF steel, integrated steel-EAF steel Cement - grey cement, white cement, clinker sent off site Lime - high calcium, dolomitic, specialty
90%	BMS – pyrometallurgical smelting of: copper; lead; nickel Iron ore pellets – flux pellets Nitrogen fertilizers - urea liquor, ammonium phosphate Petrochemicals - high value chemicals, aromatic cyclic HCs, polyethylene, higher olefins, HC solvents, styrene Petroleum refineries, Lubricants refineries, Hydrogen, Furnace black, MPMD, Metal tubes, Brick
80%	BMS – pyrometallurgical smelting of zinc; hydrometallurgical refining of: base metals; copper anodes Mining - iron ore, base metals (excluding iron, precious, uranium), uranium, gold, other precious metals, diamonds, thermal coal, metallurgical coal Ethanol – fuel, industrial Nylon 6 or 6,6 – fibers, resins Pulp and paper – a) At a facility equipped with a recovery boiler, lime kiln or pulping digester; b) At a facility not equipped with equipment in a), c) specialty products Char, Activated carbon, Iron ore pellets – pellets other than flux pellets, Potash - solution mining; Potash - conventional underground mining, Oil production - light oil, Oil production - heavy oil/bitumen, Bitumen upgrading, Natural gas pipelines, Natural gas processing, Natural gas liquids, Vaccines, Automotive, Glass, Gypsum, Mineral wool, Potato processing, Oilseed processing, Wet corn milling, Alcohol (distilleries), Citric acid, Sugar, Isopropyl alcohol

The production-weighted average emissions intensity is calculated as the total emissions of a given industrial activity (or grouping of facilities carrying out the same listed activity) divided by the total production of that sector (or activity) based on data from all Canadian facilities in that sector emitting 50 kt of CO₂e or more, generally for the years 2014, 2015, and 2016. The years 2014, 2015 and 2016 represent the most recent information available at the time the standards were developed.

The only exception to this approach is electricity generation. The output-based standard for electricity generation from solid fuels is set at 800 tonnes (t) of CO₂e/gigawatt hours (GWh) in 2019, 650 t of CO₂e/GWh in 2020, linearly declining to 370 t of CO₂e/GWh in 2030. The 2030 standard for solid fuels aligns with the standard that applies to existing gas-fired facilities in 2019. A 370 t of CO₂e/GWh standard, consistent with best-in-class performance for natural gas facilities, will maintain a price signal for many gas-fired facilities. Starting in 2021, new industrial or electricity generating facilities that start generating electricity from gaseous fuels using equipment or a unit that has a capacity of 50 megawatts (MW) or more and that is designed to operate at a thermal energy to electricity ratio of less than 0.9 will have a standard that starts at 370 t of CO₂e/GWh in 2021 declining linearly to 0 t of CO₂e/GWh in 2030. The declining standard will only apply to the increased capacity in the case of new equipment that is added that does not modify the existing electricity generation equipment. It will also apply to existing facilities that cumulatively increase their electricity generating capacity by 50 MW or more after January 1, 2021, and for which the increased capacity is designed to operate at a thermal energy to electricity ratio of less than 0.9. Recognizing that diesel is used in remote locations where lower-emitting energy options are limited, the standard for the production of electricity using liquid fuels was set at 550 t of CO₂e/GWh.

The Regulations specify a numerical output-based standard for most activities listed on Schedule 1 of the Regulations. However, as output-based standards are calculated based on facility data, divulging the output-based standard values for some sectors with only one or two facilities could compromise the confidentiality of data provided by facilities. To prevent this, facilities in those sectors undertaking activities for which the output-based standard is identified as “calculated” in Schedule 1 of the Regulations will have to calculate an output-based standard in accordance with the formula provided in the Regulations based on the current year of compliance or 2017 and 2018, at the facility’s discretion. The stringency of these calculated output-based standards is based on the same competitiveness assessment as the numerical output-based standards. ^{footnote 20}

An output-based standard will also need to be calculated by voluntary participants undertaking an activity that is not listed in Schedule 1 of the Regulations. The stringency of the calculated output-based standard for these activities is set at 80%. ^{footnote 21}

Compliance periods

Starting January 1, 2019, each calendar year will represent a compliance period within the OBPS. However, for a covered facility that is located in Yukon or Nunavut, the first compliance period begins on July 1, 2019, and ends on December 31, 2019. For facilities that did not meet the requirements of the Registration Notice but may become a covered facility in the future (i.e. voluntary participants in the OBPS), their compliance period will start on the effective date of the registration as an emitter under Part 1 of the GGPPA. ^{footnote 22} For example, if a facility’s effective date of registration as an emitter is September 1, 2019, its first compliance period would be from September 1 to December 31, 2019.

Quantification, reporting, and verification

Covered facilities will be required to quantify their emissions and production, using the methodologies prescribed in the Regulations and report these quantities annually. Covered emission types will include emissions from stationary fuel combustion, industrial processes, industrial product use, venting, flaring, leakage, on-site transportation, waste, and wastewater.

Covered facilities must provide annual facility reports that will include the facility’s annual emissions limit, total emissions, and calculated compensation obligation, as well as any additional information needed to assess the facility’s compliance with the GGPPA and the Regulations. The Regulations also contain some data gathering requirements, such as reporting on the quantity of thermal energy (i.e. steam) transferred and hydrogen sold, to help assess the need for future amendments to the Regulations. Covered facilities must arrange for their annual facility reports to be verified by a third party accredited to the ISO 14065 standard by the Standards Council of Canada, the American National Standards Institute, or any other organization that is a member of the International Accreditation Forum. Annual reports, accompanied by the associated verification report, are required by June 1st of the year following each compliance period.

Where possible, the quantification methods in the Regulations are aligned with GHGRP and otherwise with methods used in provincial reporting systems, primarily based on the Western Climate Initiative (WCI). However, due to different publication timelines, full alignment is not possible between the Regulations and the 2018 GHGRP. The Department will assess the potential for greater alignment over time.

The quantification, reporting, and verification requirements of the Regulations are aligned, with small modifications, with those of the Information Order that came into force on January 1, 2019, for covered facilities. The Regulations contain transitional provisions for the 2019 compliance period to ensure that facilities that complied with the Information Order are deemed to have complied with the Regulations.

The Minister is therefore making the Order Repealing Certain Legislative Instruments to also repeal the Information Order to avoid duplication of requirements.

Compensation

A covered facility that emits less than its annual emissions limit will receive surplus credits, with each credit representing one tonne of CO₂e. When the GHG emissions of a covered facility are above its annual limit, the facility will be required to provide compensation for its excess emissions by the prescribed deadline. ^{footnote 23} The facility can meet its compensation obligation by paying the excess emissions charge specified in Part 2 of the GGPPA or by remitting compliance units. ^{footnote 24} Compliance units include federal OBPS surplus credits, offset credits issued by the Minister (if enabled through regulations) and certain provincial and territorial GHG offset credits recognized as compliance units. ^{footnote 25} A unit or credit will be recognized as a compliance unit if it is issued under a GHG offset program and protocol that meets the eligibility criteria set out in the Regulations. The Department will publish the list of eligible offset programs and protocols on its website.

The Department will establish and maintain a system to track compliance under the OBPS, including the tracking of surplus credits and federal offset credits issued, transferred, remitted (used), and retired, as well as the use of recognized units, and payments of the excess emission charge. Beginning with the 2022 compliance period, facilities will have to pay the excess emissions charge to compensate for a minimum of 25% of their excess emissions. Surplus credits can be used as compensation for up to five years following the year the credits are issued. Offset credits and recognized units can be used as compensation for up to eight years after the year the GHG reduction or removal generating the credits or units occurred.

The regular-rate deadline to provide compensation for excess emissions is December 15 in the calendar year following a compliance period. If this deadline is missed, compensation is due at an increased rate of four to one (4:1) by February 15 of the second year following the compliance period. If the compensation for excess emissions is not provided by the increased-rate compensation deadline, the facility is out of compliance with the Regulations.

Administrative monetary penalties

The Regulations also make related amendments to the Environmental Violations Administrative Monetary Penalties Regulations. ^{footnote 26} This will enable enforcement officers to issue an administrative monetary penalty (AMP) for certain violations under the GGPPA and the Regulations. It also specifies the method used to calculate the amount of the AMP, including baseline penalty amounts for different types of violations and violators, and aggravating factors, that, if applicable, may increase the amount of the penalty.

Regulatory development

Consultation

Since 2017, the Department held over 800 hours of consultations with stakeholders and provincial partners, including webinars, teleconferences, face-to-face meetings, technical discussions and bilateral meetings. Representatives from industry, provinces, territories, environmental non-governmental organizations (ENGOs), and organizations representing Indigenous peoples participated in these consultations. In addition, a technical paper on both parts of the federal carbon pollution pricing system ^{footnote 27}, the Regulatory framework for the output-based pricing system, ^{footnote 28} and Compliance options under the federal output-based pricing system ^{footnote 29} outlining compliance units and their use under the OBPS were published to seek feedback from Canadians and stakeholders. In December 2018, the Department released further details on the proposed federal OBPS in the Regulatory Proposal for the Output-Based Pricing System Regulations under the Greenhouse Gas Pollution Pricing Act (Regulatory Proposal). ^{footnote 30}

Overview of policy changes that informed the Regulatory Proposal for the Output-Based Pricing System under the Greenhouse Gas Pollution Pricing Act

To address concerns related to industry competitiveness and carbon leakage, the Department developed and carried out an analysis of each sector’s risk to competitiveness and carbon leakage due to carbon pollution pricing using a three-phased approach. In Phase 1, historical data, primarily from national public data sources, was used to assess which sectors exceed thresholds for both emissions-intensity and trade-exposure. Phase 2 conducted the same analysis, but estimated emissions-intensity and trade-exposure using results from the Department’s EC-PRO model for projections for 2022. ^{footnote 31} Phase 3 examined submissions from stakeholders and additional factors including:

Evidence of significant impacts associated with carbon pollution pricing at 80% stringency;
The ability to pass through costs from carbon pollution pricing;
Domestic or international market considerations that could heighten competitiveness risks due to carbon pollution pricing at 80% stringency;
Consideration of indirect costs from carbon pollution pricing; and
Other specific considerations related to carbon pollution pricing that could affect the sector as a whole, a particular region within that sector, or individual facilities.

Based on preliminary results of the Phase 1 and 2 analysis, the Department revised the starting stringency for all output-based standards from 70% to 80% of national production-weighted average emission intensity, with the possibility for further adjustment for sectors assessed to be at high competitiveness and carbon leakage risk due to carbon pollution pricing at the 80% starting point. Based on the three-phased analysis, the stringency of output-based standards was adjusted to 90% for three sectors (iron and steel manufacturing, nitrogen fertilizers, petrochemicals) and to 95% for two sectors that remained assessed as high risk at 90% stringency (cement, lime).

In response to comments from smaller industrial facilities which were not eligible for voluntary participation in the proposed design of the OBPS until 2020, the Department revised its approach to allow for participation in the OBPS starting in 2019. The Department also proposed that facilities in sectors identified as being at significant risk of carbon leakage and competitiveness impacts due to carbon pollution pricing could be considered for voluntary participation.

A number of refinements were made to the proposed output metric (denominator) of output-based standards in response to comments, new data, and new information received from stakeholders. A calculated output-based standard, determined on a facility-specific basis, was added to ensure confidentiality of industry data for sectors with one or a very small number of facilities. This output-based standard can also be used in cases where facilities are designated as covered facilities under the Voluntary Participation Policy but for which no output-based standard is specified in the Regulations. The proposed treatment of electricity under the OBPS was reconsidered to encourage the decarbonization of electricity generation while mitigating electricity price impacts on businesses and households.

Consultations on the Regulatory Proposal

In December 2018, the Department released further details on the proposed federal OBPS, including the Regulatory Proposal, the Cost-benefit analysis framework for an Output-Based Pricing System (CBA Framework), ^{footnote 32} Voluntary Participation Policy, and a proposed amendment to the policy on voluntary participation for comment. Information regarding the regulatory development process was released by the Department in late 2018. ^{footnote 33} A multi-sector meeting with technical working group members and a multi-stakeholder webinar were held in early 2019. In addition, numerous bilateral and technical working group meetings were held with industry representatives to follow up on sector-specific comments.

The Department received 107 submissions, mainly from industry representatives and industry associations. Provinces and territories, Indigenous organizations or communities, non-governmental organizations, offset project developers, verification professionals, and subject-matter experts also provided comments.

Overview of feedback received on the Regulatory Proposal

The vast majority of comments received from industry stakeholders focused on the proposed stringency and the methodology used to develop the output-based standards. Additional feedback was received on the proposed output metrics of specific output-based standards and some stakeholders advocated for facility-specific standards. Others requested that the stringency of specific output-based standards be revised downward (less stringent) based on various factors including level of trade exposure, previous emissions reductions achieved at the facility, performance of global competitors, or industries’ technical or financial limitations to reduce emissions. Industries with a high proportion of industrial process emissions raised concerns over the inherent difficulty to reduce these emissions, and the time and investment needed to develop new technologies and processes to reduce process emissions over the longer term. Comments supporting both a more stringent and a less stringent approach to electricity were received. In addition, a number of comments were provided supporting inclusion of an output-based standard for steam to incentivize cogeneration and district energy systems.

Almost a third of industry stakeholder submissions stressed the importance of providing maximum compliance flexibility by removing the proposed limitations on use and expiry of compliance units. Some comments supported a further tightening of limitations on use of compliance units. A number of comments supported the creation of a federal offset system. Submissions from provincial governments, non-governmental organizations, and other industry stakeholders and subject-matter experts generally echoed industry’s comments and recommendations, although a larger focus was placed on ensuring a well-functioning and fungible credit market.

Overview of changes to the Regulatory Proposal

The Department revised aspects of the Regulatory Proposal in response to an in-depth review of stakeholders’ feedback and internal analysis using additional data provided by stakeholders. The changes made are expected to further reduce competitiveness and carbon leakage risks for Canadian industry while maintaining the incentive for industry to reduce GHG emissions. Some of the changes also reflect improved data used to develop the output-based standards, and a few will reduce administrative burden.

Overview of changes to the output-based standards

A number of output-based standards have been refined from what was proposed in the Regulatory Proposal. These changes reflect new data, better correlation between emissions and output, and in-depth review of the three-phased competitiveness and carbon leakage analysis.

Changes to output-based standards due to new data

Using new data and information, the numerical value of the output-based standard was refined for: natural gas transmission pipelines; production of rolled steel; coke-making in integrated steel production; iron-making in integrated steel production; steel production using basic oxygen furnace; production of citric acid; production of ammonium phosphate; production of urea liquor; and, production of sugar.

Changes to production metric used in output-based standards

Changes were made to the production metric used for five output-based standards to create a better correlation between emissions and output, to better align with current industry reporting practices, or to better align with the consistent approach taken across sectors. As part of these changes, four additional output-based standards were added to capture additional distinct activities at covered facilities that were not previously identified.

The output-based standard for

Oilseed processing was modified to use the input of raw materials rather than the output of finished product as the output metric (denominator);
The production of glass was modified to add separate sub-sectors, and corresponding production metrics, to account for differences in the product produced;
Precious metals was separated into the production of gold, and the production of silver, palladium or platinum as the output metric;
Automobile manufacturing was modified to remove the size of a facility from the proposed production metric;
Pulp and paper was modified to add an output-based standard for specialty products;
Isopropyl alcohol was added; and
Vaccines was modified to a calculated output-based standard.

Because the Information Order already included the requirements to quantify production in a certain manner, the oilseed, production of glass, and pulp and paper specialty products industries will be able to choose between quantifying production as per the Information Order or the Regulations for the 2019 compliance period.

Changes to output-based standards due to competitiveness and carbon leakage risk

Industry raised concerns over competitiveness and carbon leakage risks from the stringency of output-based standards. A number of stakeholders provided additional information for consideration. The Department carried out an in-depth review of the three-phased competitiveness and carbon leakage risk analysis, incorporating new information where available.

The output-based standards for sectors assessed as being at high competitiveness or carbon leakage risk due to carbon pollution pricing or with a high proportion of industrial process emissions were adjusted to 90%. For sectors that continued to be assessed as high competitiveness and carbon leakage risk due to carbon pollution pricing at 90%, or with a high proportion of industrial process emissions, a second adjustment was made to 95%. The potential to reduce process emissions will be reassessed in 2022 as part of the scheduled review of the Regulations.

In total, eleven output-based standards were adjusted to 90% stringency: base melting smelting of copper, lead, and zinc, iron ore flux pellets, metal tube production, petroleum refining, production of lubricant basestock, standalone hydrogen production, furnace (carbon) black, 2-methylpenta-methylenediamine (MPMD), and brick. Eight output-based standards were further adjusted to 95%: nitric acid, ammonia production, iron and steel integrated steel (coke-making, iron, BOF steel, and EAF steel), and iron and steel mini mills (rolled steel and cast steel).

Changes to output-based standards for the electricity sector

In regards to the output-based standard for electricity from solid fuels, which also applies to coal-to-gas units, stakeholders in Saskatchewan and New Brunswick were opposed to the declining output-based standard. They indicated that the standard is duplicative of existing regulations and would result in high costs passed through to consumers and industrial facilities. Other stakeholders commented that coal-to-gas units should not generate credits for generation below the solid fuel standard and raised concerns that the output-based standard for solid fuels would incent higher emitting generation over lower emitting generation. The Department is of the view that the output-based standard for solid fuels finds a balance that sends a signal to move to cleaner generation over time, does not deter coal-to-gas conversions, and minimizes electricity rate impacts on businesses and households where some provincial utilities will continue to use coal-fired electricity until the coal phase-out date of 2030. ^{footnote 34}

In regards to the output-based standard for electricity from liquid fuels, stakeholders commented that the standard is unachievable for heavy fuel oil facilities due to operating conditions and lack of access to lower emitting alternatives. The Department is of the view that the output-based standard for electricity from liquid fuels is consistent with the overall approach to setting output-based standards in that it provides relief while still sending a pricing signal to encourage the transition to lower/non-emitting technologies. Therefore, no change was made.

In regards to the output-based standard for electricity from gaseous fuels (i.e. 370 t of CO₂e/GWh), some industrial stakeholders commented that a 420 t of CO₂e/GWh would be more appropriate for peaking units and cogeneration. Non-emitting industry groups and environmental stakeholders commented that the standard for new gas units is not sufficient to prevent an investment in new natural gas over lower emitting generation sources, and will result in Canada falling short of the PCF target of 90% non-emitting electricity target by 2030. The non-emitting sector and ENGOs recommended a long-term signal for new investments in electricity generation to shift toward lower emissions intensity electricity generation over time, i.e. an output-based standard for new gas generation facilities that ramps down from 370 t of CO₂e/GWh to 0 t of CO₂e/GWh in 2030. The Department recognizes that, over time, new electricity generation capacity should come from non-emitting sources and agreed to implement this recommendation.

A number of comments were received indicating that, under the Regulatory Proposal, there was a disincentive for biomass electricity generation because the methane (CH₄) and nitrous oxide (N₂O) emissions from the combustion of biomass would be counted towards a facility’s total emissions in the determination of compensation, while the electricity standards do not account for emissions resulting from combustion of biomass. Conversely, some comments were received raising concern that the OBPS could incent increased demand for biomass for energy production and that this could increase the price of biomass used as a feedstock by other industries. The Department is of the view that the OBPS should avoid disincenting biomass electricity generation, and so CH₄ and N₂O emissions from the combustion of biomass have been excluded from a facility’s total emissions in the determination of compensation for the purpose of compliance. The requirement to quantify and report these emissions remains so that the exemption can be reassessed in the future.

Thermal energy approach

The majority of stakeholders indicated they were comfortable with the proposed approach to treat thermal energy (i.e. production of steam or hot water), where the emissions from thermal energy production and material transfers from other facilities are included in the output-based standards of the industrial sector products. This method aligns with the overall approach of setting standards that both incents improvement relative to the Canadian average emission intensity for the production of a given product, and incents facilities to reduce thermal energy use or to use lower emission intensity thermal energy, whether it is produced on-site or purchased from a third party.

Some utility cogeneration operators (i.e. electricity generators who sell excess steam and hot water to other regulated facilities) indicated concern that the system would not incent gas-fired cogeneration and that existing utility cogeneration facilities may be unable to recoup carbon costs for the thermal energy that they produce and sell to other facilities. Some stakeholders have indicated that the approach for natural gas fired cogeneration is overly stringent. District energy stakeholders who provide heat and/or cooling to a cluster of buildings, generally residential or commercial, raised concerns that excluding district energy systems from the scope of the OBPS and thus subjecting them to the fuel charge would increase the cost of providing this heat and/or cooling; therefore, incenting buildings to electrify instead of using district energy. Some stakeholders recommended an output-based standard be added for thermal energy.

The Department is of the view that the approach for thermal energy is the best approach to incent both the use of lower emission intensity thermal energy and improvement of process efficiency. Based on feedback from subject-matter experts and stakeholders, the Department is of the view that it is likely that cogeneration facilities will be able to pass on costs associated with thermal energy production to industrial users, either immediately or within a reasonable period of time. Industrial users are expected to use the allocation provided for thermal energy under their industrial output-based standard to either offset costs passed on by third party thermal energy providers or to account for their emissions generated on-site through the production of thermal energy.

In terms of thermal energy production for non-industrial applications, such as district energy stakeholders who provide building heat, the approach aligns with the objective of the OBPS to only cover industrial facilities that are emission intensive and trade exposed. The carbon pollution price signal on fuels and energy used by district energy consumers is expected to incentivize consumers to use lower emission energy options.

Alternate years to calculate baseline of output-based standards

Generally, output-based standards were developed based on data for 2014 to 2016 from facilities emitting 50 kt of CO₂e or more. Data from years 2014 to 2016 was used because it was the most recent period of data available when the output-based standards were being developed. Some stakeholders requested the baseline data include a larger number of years in order to represent the cyclical changes in their product lifecycles or include facilities emitting below 50 kt of CO₂e. Including additional older years of data could reduce the incentive to make incremental reductions. As well, complete data sets for facilities emitting below 50 kt of CO₂e, were not available. For consistency across sectors and to incentivize incremental reductions, no change was made to the scope of data used to set the numerical output-based standards.

Compliance periods

To reduce the administrative burden and to provide increased compliance flexibility, some stakeholders recommended the Department adopt multi-year compliance periods. The Department has maintained annual compliance periods for a number of reasons, including the annual assessment of provincial and territorial carbon pollution pricing systems against the federal Benchmark and the annual return of proceeds from the OBPS to the jurisdiction of origin to support action on carbon pollution.

Annual reporting obligation

A number of industry stakeholders suggested the introduction of two distinct deadlines for the submission of the annual report and the verification report to simplify planning and reporting and to provide more time for preparation of the verification report. Similarly, other stakeholders recommended pushing back the deadline for the submission of the annual report and the verification report to September 1 of the year following the compliance period for which the reports are being made.

After having considered various deadline options, the Department decided to maintain the deadline for the submission of the annual facility report and verification report of June 1 of the year following the compliance period for which the reports are being made. Maintaining this deadline helps to reduce administration burden on industry by aligning the submission deadline with the deadline for reporting to the federal GHGRP. It also supports development of the emissions trading market by providing facilities more time to obtain compliance units between the reporting deadline of June 1 and the compensation deadline of December 15.

Verification requirements

A materiality threshold is the threshold at which the individual or the aggregation of errors or omissions affects the reliability of reported data. Industry stakeholders as well as some verification professionals expressed concern that the ± 0.1% materiality threshold for production data was too stringent and impractical. The Department concluded that, in some cases, due to the level of uncertainty inherent in quantifying the output metric (denominator of the output-based standard), meeting the proposed materiality threshold would be challenging. As a consequence, the materiality threshold for production data has been revised to ± 5%, in line with most of the comments and recommendations received. The Department plans to review the production materiality threshold with a view to tightening it where possible over time.

The Department also modified the materiality threshold for total GHG emissions for smaller facilities (emitting below 50 kt of CO₂e annually). This materiality threshold was revised to ± 8% to account for the potential for greater uncertainty in smaller facilities’ data management systems. This materiality threshold for facilities with emissions of 500 kt of CO₂e and above remains at ± 2% to reflect the much higher impact any errors or omissions in the quantification can have on the compliance obligation.

Rules for calculated output-based standard

A number of stakeholders were concerned with using the year 2019 as the reference year for the establishment of a calculated output-based standard for facilities carrying out listed industrial activities. This year is not necessarily representative of a facility’s average emission intensity, does not incentivize reductions to be undertaken in 2019, and would include more recent efforts to reduce emissions compared to the sector output-based standard, which uses data from 2014 to 2016. In recognition of these concerns and to better align with the general approach to setting output-based standards, the Department added the option to calculate the output-based standard using the 2017–2018 data years, if data is available. This is aligned with the approach for facilities that are not undertaking a listed activity and are admitted under the Voluntary Participation Policy. It also aligns with data availability from smaller facilities that started reporting to GHGRP in 2017. The Department intends to develop additional sector output-based standards over time.

Limitation on the use of compliance units

A number of stakeholders strongly opposed the proposed limit on the use of compliance units (surplus credits, offset credits and recognized units) because it would reduce access to potentially lower cost compliance options, and impede the development of a properly functioning emissions trading market. Specific recommendations included removing the limit on the use of compliance units, extending the lifetime of surplus credits and recognized units, and expanding the criteria of eligible recognized units to ensure all provincial and territorial protocols and offset credits can be used under the OBPS. Another recommendation was to allow the use of credits or units from another country (Internationally Transferred Mitigation Outcomes or ITMOs) under the OBPS.^{footnote 35} Some comments also supported a further tightening of the limit on use of compliance units.

A limitation on the use of compliance units, as well as the expiry of credits, are common rules in other emissions trading systems to maintain the carbon pollution price signal. The system designers seek to achieve the right balance between stringency of standards and compliance flexibility. If too many credits are available, the price signal, which drives emission reductions, could be weakened. Introduction of these rules at the start of the OBPS will ensure that if there is an oversupply of credits, a price signal will be maintained, and will also allow facilities to plan their compliance strategy in advance. The Department will postpone the 25% minimum excess emission charge payment to the 2022 compliance period to allow covered facilities more time to use and trade compliance units and for the Department to collect data to assess whether oversupply is occurring. The minimum excess emission charge payment will be reassessed in 2022 as part of the scheduled review of the Regulations.

The Department will assess provincial and territorial GHG offset programs and protocols based on criteria informed by the pan-Canadian GHG offsets framework developed by the Canadian Council of Ministers of the Environment to ensure the offset credits meet a consistent standard to be recognized as compliance units. New provincial or territorial GHG offset systems will be assessed against the program criteria as they are implemented. The Department may consider amending the Regulations to allow for ITMOs once negotiations under Article 6 of the Paris Agreement are complete.

Cost-benefit Analysis (CBA) Framework consultations

The Department published the proposed CBA Framework in December 2018. Comments received raised concerns that the Department’s CBA will not assess the cumulative impacts of the OBPS, the fuel charge (Part 1 of the GGPPA), the GGPPA in its entirety, the Clean Fuel Standard (CFS), and other PCF regulations. An industry stakeholder also raised concerns that there was no plan for a publication of a separate CBA for the fuel charge. The CBA includes all existing federal and provincial policies in place including the fuel charge, as well as relevant economic data, as part of the baseline. This is consistent with the Treasury Board Secretariat (TBS) guidelines for CBA. The intent is to capture the incremental impacts of the Regulations relative to the existing regulatory landscape. The cumulative impacts of all PCF regulations, and the fuel charge specifically, are outside the scope of this regulatory analysis. However, these impacts are being discussed with industry and stakeholders through a multi-stakeholder committee process and sector case studies looking at the cumulative impacts of regulatory measures.

Prepublication

In order to apply the federal OBPS starting on January 1, 2019, an exemption was granted from the regulatory policy requirement to officially publish draft regulations for the OBPS in the Canada Gazette, Part I. To ensure stakeholders had the opportunity to provide feedback on the regulatory details of the proposed OBPS, the Department published the Regulatory Proposal on its website in December 2018 for comment. In addition, the Department has undertaken extensive pre-consultation with stakeholders on details regarding the Regulations, including publishing a technical paper, a draft regulatory framework, and seeking feedback through multiple engagement sessions and working groups totalling over 800 hours of engagement.

Modern treaty obligations and Indigenous engagement and consultation

Modern treaty obligations

In accordance with the Cabinet Directive on the Federal Approach to Modern Treaty Implementation, an Assessment of Modern Treaty Implications was conducted. The initial assessment examined the geographic scope and subject matter of the initiative in relation to modern treaties in effect and did not identify any modern treaty implications at this time. The initiative is outside the scope of the subject matter contained in modern treaties. While no modern treaty implications were found based on the examination of the federal carbon pollution pricing system, the Government of Canada is committed to engaging with Indigenous peoples to find solutions to their unique circumstances in relation to carbon pollution pricing, including high costs of living and energy, particularly in remote communities.

Indigenous engagement and consultations

The federal government engages Indigenous peoples on climate change policy via senior distinctions-based bilateral tables with First Nations, Métis, and Inuit. The Department and Finance Canada have participated in the table meetings, starting in October 2017, to build relationships, share information, and gather feedback from Indigenous peoples on the development of the Pan-Canadian Approach to Pricing Carbon Pollution. Technical briefings were provided throughout 2018 to all groups as components of the federal plan were released, such as proposed legislation for the federal carbon pollution pricing backstop, the Regulatory Proposal, and the potential use of offsets in the federal system.

Most feedback to date has focused on the federal fuel charge portion of the federal backstop and that Indigenous peoples receive an equitable share of carbon pollution pricing proceeds in all regions of the country. While no specific issues have been raised with the Regulations by organizations of Indigenous peoples, it was noted by some west coast First Nation communities that their existing carbon offset project should be included in a federal offset program if developed. Indigenous representatives also raised concerns with the impact of carbon pollution pricing on Indigenous communities, for example due to already-high energy costs, low household incomes, and limited access to alternatives. Some Indigenous governments have indicated they would have preferred to be fully exempted from carbon pollution pricing; others indicated they wished to receive proceeds directly. National Indigenous organizations have consistently expressed a desire to be engaged on proceed use, and have been critical of the lack of formal and meaningful engagement on the development of the federal approach as a whole.

The exemption from the fuel charge for diesel used for electricity generation in remote communities and the exemption of the fuel charge on aviation fuels in the territories will help to reduce impacts on remote Indigenous communities, as will proposed funding for Indigenous communities from fuel charge proceeds.

The federal government will continue to engage with Indigenous peoples with respect to pricing carbon pollution. Canada intends to engage with Indigenous peoples in jurisdictions where the federal government is managing the returns of the proceeds (i.e. Saskatchewan, Manitoba, Ontario, and New Brunswick) in order to co-develop innovative solutions for the return of fuel charge proceeds to Indigenous communities in those jurisdictions.

Instrument choice

Regulations are required in order to implement the OBPS as set out in Part 2 of the GGPPA. There is flexibility, however, in terms of whether or not to further prescribe rules around some key elements of the system in regulations. The Department considered the merits of regulatory and non-regulatory approaches with respect to the issuance of surplus credits, the designation of covered facilities, the retirement and voluntary cancellation of compliance units and the recovery of compensation.

The Department concluded that regulations should be made for the application of the issuance of surplus credits to provide certainty to regulatees. Therefore, the Regulations include circumstances under which surplus credits will be issued. To ensure records are easily accessible to enforcement officers, the Regulations include requirements that specify where the records must be kept and the obligation to inform the Minister when records are relocated.

The GGPPA allows the Minister to designate a facility as a covered facility. Instead of including rules regarding voluntary participation in the Regulations, the Department has decided to proceed with the Voluntary Participation Policy to set out the considerations that will guide the Minister’s decision. The decision not to include rules related to voluntary participation in the Regulations was made to provide flexibility to adjust the policy over time to account for new EITE sectors. This approach is aligned with the intent of the GGPPA to mitigate climate change by reducing GHGs in a manner that minimizes the risks to competitiveness and of carbon leakage. Requirements related to the voluntary cancellation of a designation under the GGPPA were also not included in the Regulations.

The Department has considered that the provisions of the GGPPA on the retirement of compliance units, the voluntary cancellation of compliance units, and the recovery of compensation contain sufficient details to allow for the proper functioning of the OBPS. Over the next few years, the Department will monitor the use of these provisions to determine if requirements should be added to the Regulations following the review scheduled in 2022.

Regulatory analysis

The regulatory analysis compares a “Regulatory Scenario” (the Regulations) to a “Baseline Scenario” where the full fuel charge applies to all industry. The analysis of benefits and costs then assesses the monetary value of the relief from the fuel charge that the OBPS provides to EITE facilities, and evaluates the mitigation of competitiveness pressures in terms of increased production across sectors and within each backstop jurisdiction (distributional analysis). The Regulations increase administrative costs for government and industry, as well as verification costs for industry. Increases in sectoral production contribute to increases in overall gross domestic product (GDP), which improve the economic welfare of households (social benefit) but also increase GHG and air pollutant emissions (social costs), compared to the Baseline Scenario of a fuel charge on all industrial fuel use.

The cost-benefit analysis uses a general equilibrium (GE) model of the economy to estimate the monetized increases in household welfare, and the quantified increases in domestic GHG emissions resulting from the application of the OBPS (Regulatory Scenario) rather than the fuel charge (Baseline Scenario). The analysis uses the Social Cost of GHGs to monetize the costs of increased domestic GHG emissions.^{footnote 36} The monetized administrative and verification costs of the OBPS are estimated separately in the cost-benefit analysis. A monetized analysis of reduced carbon leakage (social benefit) or the negative impact of increased air pollution (social cost) was not possible, and these impacts are assessed qualitatively.

By 2030, compared to the Baseline Scenario in which the fuel charge applies to all industrial emissions in backstop jurisdictions, the Regulations are expected to lead to an improvement in household welfare of $3.2 billion, which is an estimate of the value households derive from increased consumption. Overall, 290 facilities are expected to be covered by the OBPS.^{footnote 37} While the Regulations will provide these facilities with a financial incentive for continuous emission reductions, there will be slightly fewer domestic GHG emission reductions than would have occurred under the Baseline Scenario. This is due to greater production in the Regulatory Scenario. The cumulative foregone domestic GHG reductions are estimated to be 22 Mt of CO₂e over the 2019–2030 period and the estimated cost of global climate damages associated with these emissions is approximately $916 million. The industry verification and administrative costs are estimated at $129 million, and the government administrative costs are estimated at $25 million. The monetized net benefits of the Regulations compared to the Baseline Scenario are therefore approximately $2.15 billion.^{footnote 38}

Figure A: Costs and benefits of the Regulations relative to the Baseline Scenario of a fuel charge

Detailed information can be found in the surrounding text.

Analytical framework

TBS guidance: The impacts of the Regulations have been assessed in accordance with the TBS Canadian Cost-Benefit Analysis Guide.^{footnote 39} Regulatory impacts have been identified, quantified, and monetized where possible, and compared incrementally to a Baseline Scenario.

Key impacts: The expected key impacts of the Regulations compared to the Baseline Scenario are demonstrated in the logic model (Figure B) below. The Regulations will result in benefits, such as increases in household welfare and the mitigation of carbon leakage risks, and costs, such as foregone domestic GHG and air pollutant emission reductions, as well as administrative costs for industry and government and verification costs for industry. Distributional impacts, such as sector-specific and region-specific results, are analyzed separately.

Figure B: Impacts of the Regulations compared to the Baseline Scenario of the fuel charge on all industrial fuel use

Detailed information can be found in the surrounding text.

Baseline Scenario (fuel charge applied to all industrial fuel use in backstop jurisdictions): The Baseline Scenario assumes that non-backstop jurisdictions operate their own carbon pollution pricing systems, which are aligned with the elements of the federal Benchmark. In backstop jurisdictions, Part 1 of the Act (the fuel charge regime) would apply to all fossil fuels used. The Baseline Scenario therefore assumes that only the fuel charge regime is implemented in backstop jurisdictions, meaning that the fuel charge would generally apply to all fossil fuels used by EITE facilities in backstop jurisdictions. The Baseline Scenario does not include a quantification of the potential carbon leakage associated with the full application of the federal fuel charge in backstop jurisdictions.

Regulatory Scenario: In the Regulatory Scenario, the OBPS is applied in backstop jurisdictions. The fuel charge does not apply to fuel that is used at covered facilities. Covered facilities are required to compensate for the portion of their emissions exceeding their facility limit.

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 difference in the impacts that result from applying the OBPS rather than the fuel charge.

Time frame of analysis: The time frame considered for this analysis is 2019 to 2030. The Regulations are effective as of January 1, 2019 (July 1, 2019, for Yukon and Nunavut), thus providing relief from the fuel charge set at $20/t of CO₂e, which started as of April 1, 2019 (July 1, 2019 for Yukon and Nunavut), for fuel purchased by covered facilities for use at the facility. In any given year within the analysis time frame, the estimated benefits exceed the costs, as shown in Figure A above. Therefore, the 2019–2030 time frame is considered sufficient for estimating whether the Regulations will achieve the objectives of the OBPS.^{footnote 40}

Monetary results: All monetary results are presented in 2018 Canadian dollars and non-2018 prices are inflated using GDP Deflator data obtained from Finance Canada. When shown as present values, future year impacts have been discounted at 3% per year as per TBS guidance, to 2018 (the base year of the analysis).

Regulatory coverage

The Regulations define mandatory participants as any facility in a backstop jurisdiction that carries out an activity listed in Schedule 1 of the Regulations as its primary activity and that has reported annual emissions of 50 kt of CO₂e or more to the GHGRP, for the 2014 reporting year or any calendar year thereafter. Other trade exposed facilities in backstop jurisdictions are able to apply to participate on a voluntary basis as a covered facility (opt-in). These facilities can opt-in if they reported annual emissions of 10 kt of CO₂e or more, for the 2017 reporting year or any calendar year thereafter.^{footnote 41} For the purposes of this analysis, the model assumes that all facilities in covered sectors that produce a product or conduct an activity for which an output-based standard exists will opt into the OBPS to reduce their compensation obligation.^{footnote 42} In the backstop jurisdictions in 2019, 42% of GHG emissions are estimated to be covered by the fuel charge and 27% by the OBPS, with a total of 69% of emissions covered by the federal carbon pollution pricing regime (i.e. the GGPPA).

Table 1 outlines the various subsectors and activities that have been assigned an output-based standard in the Regulations. Facilities from sectors listed in Appendix A to the Voluntary Participation Policy that are undertaking other activities may also apply to participate in the OBPS. Additional sectors, beyond those currently listed in the policy, may be added in the future as per the Voluntary Participation Policy released in March 2019. This allows facilities to apply to have their sector considered if it is not on the current list, but is demonstrably at significant risk of carbon leakage and competitiveness impacts from carbon pollution pricing.

There is partial coverage in Prince Edward Island and Saskatchewan since Prince Edward Island has a provincial carbon levy and Saskatchewan is implementing its own output-based pricing system. Prince Edward Island is not fully covered under the GGPPA as it has its own fuel charge and is not listed in Part 1 of Schedule 1 of the Act. Saskatchewan’s OBPS applies to large industrial facilities with the exception of electricity generation and natural gas transmission pipelines (the federal OBPS applies to these two sectors).

Modelling

There are typically two methods of analysis to calculate the impacts of regulations: partial equilibrium and general equilibrium. Partial equilibrium is commonly used when the regulatory action affects a single or few closely related markets, whereas general equilibrium (GE) is best utilized when the regulatory action is expected to cause significant impacts to the macro-economy, including production. The Regulations are expected to affect production in various markets in the Canadian economy, thus this analysis uses a GE model to calculate the impacts of the Regulations.^{footnote 43}

The Baseline Scenario and the Regulatory Scenario have been modelled using EC-PRO, the Department’s peer-reviewed, multi-region, multi-sector, provincial-territorial computable general equilibrium (CGE) model of climate change policies. EC-PRO is able to assess the variables of interest, including GHG emissions, household economic welfare, GDP and gross value added (GVA). EC-PRO simulates the Canadian economy and calculates the impacts of the Regulations by calculating the new set of prices and variables that will return the economy to equilibrium. The incremental impacts of the Regulations can be estimated by comparing the CGE equilibrium results from the baseline case scenario (fuel charge only regime) to the Regulatory Scenario (OBPS).

Emission changes 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. 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 emission changes can also be attributable to changes in production.

EC-PRO assumes that households own labour and capital (factors of production), thus the households receive all wages and profits. As production increases (or decreases) the demand for labour and capital inputs may also increase (or decrease). Factor prices are equal to the marginal revenue received by firms from employing an additional unit of labour or capital, and households allocate income from sales of these productive factors to the consumption of goods to maximize welfare. In response to any changes in incomes or relative prices, households may modify their consumption patterns in terms of their overall level of consumption and the mix of goods and services they choose to consume. The trade-off between consumption and leisure is not captured in EC-PRO.

EC-PRO captures important differences between provinces and territories and forecasts the domestic impacts of the federal backstop system. EC-PRO simulates the response to the OBPS in Canada’s main economic sectors in each jurisdiction, and models the interactions between sectors, including interprovincial trade. It captures characteristics of provincial production and consumption patterns through a detailed input-output table and links provinces and territories by means of bilateral trade. Each province and territory is explicitly represented as a region; the representation of the rest of the world is reduced to import and export flows to Canadian provinces, which are assumed to be price takers in international markets. Finally, to accommodate analysis of energy and climate policies, the model incorporates information on energy use, combustion and non-combustion emissions.

The model accounts for the trading of credits by assuming that facilities that emit below their annual facility emissions limit earn the value of the credit instead. Crediting is modelled as a subsidy to facilities that emit below their limit, and this subsidy is valued at the federal carbon pollution price level for each year. The model does not account for trading partners for these credits or banking behaviour; thus, it is assumed that the facilities earn the value of the carbon pollution price for the respective year instead.

A key input into the EC-PRO modelling is the Department’s 2017 GHG Reference Case (the 2017 Reference Case).^{footnote 44,}^{footnote 45} This reference case includes the future impact of policies and measures taken, or announced in detail, by the federal, provincial and territorial governments as of fall 2017, including carbon pollution pricing systems in British Columbia, Alberta and Quebec. In the Baseline Scenario, the EC-PRO modified 2017 Reference Case assumes that non-backstop jurisdictions operate their own carbon pollution pricing systems that remain aligned with the elements of the federal Benchmark. In the 2017 Reference Case, key macroeconomic variables such as GDP, the exchange rate and inflation are aligned to Finance Canada’s projections. The economic projections to the year 2021 are calibrated to Finance Canada’s Budget 2017 fiscal outlook.^{footnote 46} The years 2022–2030 are based on Finance Canada’s Long-Term Economic and Fiscal Projections. Population growth projections are obtained from Statistics Canada and updated in engagement with provinces and territories. Forecasts of oil and natural gas prices and production are taken from the National Energy Board’s 2017 Canada’s Energy Future publication.^{footnote 47} model uses the most up-to-date data at the time of modelling; assumptions and data may change over time, which is not reflected in the model.

In EC-PRO, the backstop (the federal carbon pollution pricing system in jurisdictions listed in Part 2 of Schedule 1 to the Act) is modelled as a carbon pollution price that applies to the purchase of all fossil fuels that produce GHG emissions when combusted, at a price of $20/t of CO₂e in 2019 (the first year the federal system took effect), rising by $10/t of CO₂e annually to $50/t of CO₂e in 2022. The analysis assumes that the $50/t of CO₂e is maintained until 2030. To create the Regulatory Scenario, EC-PRO models the OBPS by providing each sector-region pair with an output-based “rebate,” which is applied to the Baseline Scenario referenced above, and corresponds with the stringency of the sector-specific output-based standards for the covered facilities in backstop jurisdictions. The model also takes into account the difference in emissions coverage between the Baseline Scenario, which only covers combustion emissions, and Regulatory Scenario, which also covers non-combustion emissions. For industrial sectors in backstop jurisdictions that are not covered by the OBPS, the analysis assumes that the carbon pollution price is set at $15/t of CO₂e for the first compliance period (2019). This assumption was made to model a partial year, as the fuel charge came into effect on April 1, 2019 (July 1, 2019, for Yukon and Nunavut).

For example, if an output-based standard is established at 80% of a given sector’s average GHG emissions intensity (emissions per unit of output) for a production activity, the carbon pollution price would be imposed on all GHG emissions covered by the OBPS (i.e. on all covered emissions, including both process and combustion emissions). The model would then return 80% (the stringency of the sector’s output-based standard based on emissions per dollar of output) of the proceeds generated from the imposition of the OBPS (“the rebate”) to the sector after the carbon pollution price has been paid (or the credits, represented in the model as a subsidy, have been given to the sector).^{footnote 48} This modelled output-based standard is scaled by region and sector to align with the portion of GHG emissions from facilities in backstop jurisdictions within the given sector that are required to participate in the OBPS. Sectors in the EC-PRO model are at a higher level of aggregation than the output-based benchmarks. The applicable output-based standard is scaled based on comparisons of sectoral GHG emissions from the GHGRP and the National Inventory Report.^{footnote 49}

Pollution pricing costs for EITE facilities

Facilities that exceed their limit will be required to provide compensation to the government for the emissions that exceed their annual facility emissions limit. In general, the OBPS is anticipated to reduce the costs of carbon pollution pricing for facilities subject to the Regulations, relative to the Baseline Scenario (see Table 4 below). In EC-PRO, each sector is modelled as one representative firm per province or territory. Therefore, the results demonstrate the impacts for each sector and do not reflect the performance of individual facilities. The model incorporates facility improvements over time, for example technological and equipment upgrades, and general maintenance.

The model results for three sectors in backstop jurisdictions show them as already below the national historic intensity level (modelled as emissions per dollar of output, instead of emissions per physical unit of output in the Regulations) when the OBPS begins. These results are not aligned with the departmental competitiveness analysis of historical facility level data. This difference can be attributed to the fact that the EC-PRO model assumes emissions intensity improvements over time, including improvements due to carbon pollution pricing. Furthermore, the regional distribution of intensities differ and certain sectors are more aggregated in the model than in the Regulations. There are also differences in the emissions intensity metric modelled as compared to the metric used in the Regulations. The departmental competitiveness analysis concludes that at the outset of the OBPS, each sector at the provincial/territorial level would have a compensation requirement based on their respective emissions intensity.

Table 4: Carbon pollution pricing costs in backstop jurisdictions in 2022 by sector (millions of dollars)
Sector	Baseline Scenario (Fuel charge)	Regulatory Scenario (OBPS)
Cement	66	9
Chemical, plastics, and rubber manufacturing	217	−201
Oil and gas extraction	3	−4
Electric power generation, transmission, and distribution	860	130
Food, beverage, and tobacco manufacturing	106	67
Non-metallic mineral product manufacturing	37	−12
Other mining	123	4
Petroleum and coal products manufacturing	317	89
Primary metal manufacturing	187	26
Paper manufacturing	77	22
Transportation equipment manufacturing	57	3
Wood product manufacturing	13	10
Total	2,063	144

Note: The model accounts for the carbon pollution pricing costs and output-based standard for pipelines. However, pipelines are included in the models’ aggregate transportation sector and sectoral estimates are therefore not included in Table 4 as they are not representative of the pipeline sector.

The compensation obligation is based on the national historic intensity levels from 2014 to 2016 for each sector. This national average is calculated based on emissions from backstop and non-backstop jurisdictions. In cases where the most carbon efficient facilities are outside of backstop jurisdictions, the compensation obligations for representative firms within the backstop jurisdictions are more significant.

The OBPS could result in increased costs for some facilities with relatively high levels of emissions that are not due to stationary combustion activities, but are nonetheless associated with production processes (i.e. industrial process emissions). The fuel charge applies to fossil fuels that result in GHG emissions by means of combustion (i.e. combustion emissions), but not the process emissions. By contrast, the OBPS generally applies to all types of emissions, including fugitives, non-combustion emissions, etc. Some industrial facilities may have more overall emissions from non-combustion emissions than from stationary combustion. Such cases are expected to be limited given the design and flexibilities of the OBPS.

In this analysis, the carbon pollution price cost savings attributable to the application of the OBPS, instead of the fuel charge, are considered a transfer payment from the government to EITE facilities in this analysis. Transfer payments are financial payments in which no goods or services are being paid for. Transfer payments are typically netted out of a CBA because the cost of the payment is offset by an equal but opposite benefit. Therefore, these policy impacts are not included in the CBA.

Benefits

As a result of the cost relief provided to facilities under the OBPS, domestic production is estimated to be higher in the Regulatory Scenario (in which the OBPS applies) than it would be in the Baseline Scenario (in which the fuel charge applies). Due to this increase in domestic output, household income and consumption also increase. A recommended measure of household welfare in general equilibrium models, such as EC-PRO, is equivalent variation (EV).^{footnote 50} EV is based on the concept of willingness-to-pay: the maximum amount a household would pay for a particular good or service, given its budget constraint. The change in EV from the Baseline Scenario to the Regulatory Scenario represents the additional amount of money that households would require in the Baseline Scenario to make themselves as well off as they would be with the OBPS.^{footnote 51,}^{footnote 52} This amount can be considered equivalent to the change in welfare that households derive from the increase in consumption under the OBPS.

As demonstrated in Table 5 below, between 2019 and 2030, the household welfare benefit attributable to the Regulations is estimated at $3.2 billion.

Table 5: Cumulative impacts on household welfare resulting from the application of the OBPS (the Regulatory Scenario) instead of the fuel charge (the Baseline Scenario) (millions of dollars)
Year	2019–2022	2023–2026	2027–2030	Cumulative (2019–2030)
Change in household welfare	631	1,087	1,505	3,224

Note: Totals may not sum due to rounding.

Costs

The OBPS provides relief to EITE industry by requiring covered facilities to pay the carbon pollution price only on the portion of their GHG emissions exceeding their annual facility emissions limit. Facilities have a similar incentive to improve emissions intensity under both scenarios. Since facilities face a lower carbon cost in the Regulatory Scenario, however, there is a reduced risk that they will shift their production to other jurisdictions. In the modelling conducted for this analysis, OBPS facilities are expected to respond to lower costs with higher domestic production. This increase in domestic output is expected to result in slightly fewer domestic GHG and air pollutant reductions than would have occurred under the Baseline Scenario. This is represented as the social cost of the Regulations. There are also industry verification and administrative costs and government administrative costs associated with the Regulations.

Foregone domestic GHG emission reductions

Foregone domestic GHG emission reductions estimated by the model to result from the application of the OBPS compared to the application of the fuel charge to all industrial emissions can be represented by a cost to society in the form of future climate damages. The difference in emissions in the Regulatory Scenario relative to the Baseline Scenario is demonstrated in Figure C below. Relative to the Baseline Scenario, the foregone domestic GHG emission reductions will increase annually as the carbon price rises until 2022. For the years following 2022, it is assumed that the carbon price will remain at $50/t of CO₂e, and the output-based standards are unchanged.

Figure C: Foregone domestic GHG emission reductions

As the incentive to reduce emissions intensity created by the fuel charge is maintained by the OBPS, technological change is modelled similarly in the Baseline and Regulatory Scenarios (with the exception of non-combustion emissions). As a result, incremental changes in GHG emissions under the OBPS are driven by increased production relative to the full fuel charge scenario.

These estimates are likely to be overestimated because they do not account for the carbon leakage avoided by the application of the OBPS rather than the fuel charge. It is expected that some of the domestic GHG emissions that are emitted after the implementation of the OBPS would have likely been emitted outside of Canada under the Baseline Scenario due to carbon leakage, as a result of the full application of the fuel charge. If the Department had been able to estimate how much of the foregone production in the Baseline Scenario would have shifted outside of Canada, where exactly it would have shifted to, and the carbon intensity of production in those locations, then it would have been possible to quantify increases in international emissions in the Baseline Scenario. This increase could offset the increased domestic GHG emissions in the Regulatory Scenario. The extent of this offsetting effect would depend on the extent of carbon leakage and carbon intensity of production in foreign jurisdictions. The OBPS is expected to reduce the risks of carbon leakage; thus, the estimated foregone emissions reductions are likely to be overestimated.

The sectoral distribution of GHG emissions reductions is demonstrated in Table 6. The majority of sectors are expected to have fewer GHG emissions reductions under the OBPS. For example, the relief from the fuel charge provided to the aggregated “electric power generation, transmissions and distribution” sector is estimated to result in fewer emissions reductions in the Regulatory Scenario relative to the Baseline Scenario. In some sectors, the level of GHGs emitted under the OBPS is lower than the fuel charge, given that the OBPS covers non-combustion emissions. For example, the “chemical, plastics, and rubber manufacturing” sector emits relatively more non-combustion emissions. This additional coverage causes reductions under the OBPS that the fuel charge would not have incentivized.

Table 6: GHG emissions reductions in 2022 by sector (Mt CO₂e)
Sector	Baseline Scenario (Fuel charge)	Regulatory Scenario (OBPS)
Cement	0.33	0.20
Chemical, plastics, and rubber manufacturing	0.33	0.54
*Oil and gas extraction^{table e4 note }**	0.00	0.00
Electric power generation, transmission, and distribution	2.90	0.75
Food, beverage, and tobacco manufacturing	0.16	0.16
Non-metallic mineral product manufacturing	0.11	0.09
Other mining	0.13	0.12
Petroleum and coal products manufacturing	0.35	0.29
Primary metal manufacturing	1.10	1.14
Paper manufacturing	0.18	0.18
Transportation equipment manufacturing	0.09	0.09
Wood product manufacturing	0.02	0.04
Total	5.70	3.60
Table e4 note(s) Table e4 note * Note: Numbers below 0.005 are shown as 0.00 in this table. Return to table e4 note * referrer

Note: The model accounts for the carbon pollution pricing costs and output-based standard for pipelines. However, pipelines are included in the models’ aggregate transportation sector and sectoral estimates are therefore not included in Table 6 as they are not representative of the pipeline sector.

The Social Cost of GHGs is applied to the expected incremental increases in domestic GHG emissions incurred in the Regulatory Scenario (foregone decreases that occur in the Baseline Scenario). The Social Cost of GHGs is a measure of the incremental damages incurred as a result of an increase in GHG emissions; these damages are considered to be distributed globally. There are two unique aspects to climate change that justify the use of global values to estimate the value of the benefits of GHG reductions: (1) it involves a global externality, where emissions anywhere in the world contribute to global damages; and (2) the only way to effectively address climate change is through global action. The Department uses the Social Cost of Carbon (SCC), the Social Cost of Methane (SCCH₄) and the Social Cost of Nitrous Oxide (SCN₂O) to estimate the monetary value of changes in emissions of carbon dioxide, methane and nitrous oxide, respectively. Using the Social Cost of GHGs, the incremental cost of foregone domestic GHG emission reductions is approximately $916 million over the twelve-year period of the analysis. As noted above, this analysis does not estimate the monetized benefit of avoided carbon leakage; as a result, this cost is likely overestimated.

Foregone reductions in air pollutants

EC-PRO was chosen to model the Regulations because it takes into consideration the macro-economic impacts of the Regulations. However, air pollutant emissions are not currently an output of this model. In addition, while the Department’s Reference Cases include published estimates of both GHG and air pollutant projections to 2030, neither the 2017 nor the 2018 Reference Cases have incorporated the impacts of the fuel charge on emissions in backstop jurisdictions. Options for estimating the change in these emissions were therefore limited at the time of analysis.

Therefore, these impacts were assessed qualitatively. In the baseline, it is reasonable to expect that, since a fuel charge will reduce GHG emissions, it would also reduce other emissions, and on balance, this would be expected to have a positive overall effect on air quality. Relative to the reductions in air pollutants from the Baseline Scenario, the Regulatory Scenario is expected to result in fewer reductions in these pollutants and fewer air quality benefits in some locations in Canada.

Industry verification costs

In order to comply with the Regulations, covered facilities must arrange for their annual reports to be verified by an accredited third party. The Department estimates that the costs of third-party verification under the Regulations will range from $5,000 to $40,000 per facility report.^{footnote 53} The costs will vary depending on a number of factors, such as complexity of GHG sources at the facility, number of verifications at the facility, verification body supply, and travel costs (the Regulations apply in some northern locations). The cumulative verification cost for the 122 mandatory facilities and 168 voluntary facilities is estimated to be $104 million between 2019 and 2030.^{footnote 54,}^{footnote 55}

Industry and government administrative costs

In this analysis, facilities that are eligible for voluntary participation under the Voluntary Participation Policy are assumed to be part of the OBPS and thus incur administrative costs as well. This assumption was included to align with the rest of the CBA, which assumes eligible facilities will opt in. It is possible that not all facilities identified by the Department as eligible to participate in the system will decide to opt in, since factors such as administrative and verification costs will impact facilities’ decisions. Therefore, administrative costs may be overestimated.

The facilities that are already registered in the OBPS will incur annual costs related to learning, information gathering, quantification, reporting, and verification. Facilities that opt in will incur registration costs. New registrants must apply for registration of their respective facility with the Minister by means of the Department’s single window information management system.^{footnote 56,}^{footnote 57} This registration process will lead to one-time, upfront registration costs for new OBPS participants in 2019. If the Minister is satisfied that an application for registration meets the applicable requirements, the facility will be registered and receive a covered facility certificate. Covered facilities will be required to retrieve and record information to comply with the requirements, and quantify and report their emissions and production. Industry administrative costs are estimated to be $25 million between 2019 and 2030.

The Department will incur costs to enforce the Regulations. A one-time cost of approximately $700,000 is required for training, intelligence and strategy development. The annual enforcement costs are estimated to be $220,000 for inspections, measures to deal with alleged violations, investigations, prosecutions and ongoing intelligence. In total, enforcement costs are estimated to be $3 million between 2019 and 2030.

Implementation of the Regulations will involve the development, operation and maintenance of information technology (IT) solutions for registration, reporting and tracking as well as compliance promotion activities. The costs of compliance promotion activities include a helpdesk and general inquiries line, and operational activities such as application and report review, oversight of credit issuance and tracking. In total, the government administrative costs, comprised of enforcement, implementation and compliance promotion costs, are estimated to be $25 million between 2019 and 2030.^{footnote 58} For further information on administrative cost assumptions, please refer to the “‘One-for-One’ Rule” section. Table 7 below summarizes the industry verification and administrative costs and government administrative costs.

Table 7: Administrative and verification costs for industry and administrative costs for government (millions of dollars)
	2019–2022	2023–2026	2027–2030	Cumulative (2019–2030)
Industry administrative costs	10	8	7	25
Industry verification costs	32	38	34	104
Government administrative costs	13	7	6	25
Total administrative and verification costs	54	53	47	155

Note: Numbers may not add up due to rounding.

Summary of benefits and costs

By 2030, compared to a scenario in which the fuel charge applies to all industrial fuel use in backstop jurisdictions, the Regulations are estimated to result in an overall increase in economic output. This is expected to improve household welfare by $3.2 billion due to increased consumption. The increase in domestic production is also expected to decrease cumulative domestic GHG emission reductions by 22 Mt of CO₂e, valued at $916 million. The cumulative administrative and verification costs of the OBPS are estimated to be $155 million. The increase in household welfare minus the cost of foregone domestic GHG emissions reductions and administrative and verification burden results in an estimated monetized net benefit of $2.15 billion. These results do not account for the reduced carbon leakage or air pollution impacts.

Table 8: Summary of benefits and costs of the Regulatory Scenario (application of the OBPS)
Impacts	2022	Cumulative (2019–2030)
MONETIZED IMPACTS (millions of dollars)
Benefits to Canadians
Household welfare gains	179	3,224
Climate costs
Foregone domestic GHG emission reductions^{table e6 note *}	86	916
Costs to industry and government
Industry administrative costs	2	25
Industry verification costs	10	104
Government administrative costs	2	25
Total costs	101	1,071
Net benefits	79	2,153
QUANTIFIED IMPACTS (Mt of CO₂e)
Foregone domestic GHG emissions reductions	2	22
QUALITATIVE IMPACTS
Global climate benefits: reduced risk of carbon leakage Domestic environmental and health costs: fewer gains in domestic air quality
Table e6 note(s) Table e6 note * Does not account for the benefit of reduced carbon leakage compared to the Baseline Scenario (application of the fuel charge to all industrial emissions). Return to table e6 note * referrer

Note: Numbers may not add up due to rounding.

Distributional analysis of competitiveness impacts by sector and jurisdiction

The Regulations will provide various sectors with relief from the fuel charge. In recognition that not all OBPS sectors will be equally impacted, the Department worked in consultation with stakeholders to assess competitiveness impacts due to carbon pollution pricing at the sector and facility levels. This work was used to determine the degree of relief provided to maintain sector competitiveness and minimize carbon leakage risk. Factors that were considered relevant to the competitiveness assessments included:

Level of direct carbon pollution pricing costs relative to economic metrics including GVA, profitability, and revenues;
Ability to pass on costs as demonstrated by trade exposure;
Evidence of significant facility-level impacts;
Domestic or international market considerations that could heighten competitiveness risks;
Consideration of indirect costs associated with carbon pollution pricing; and
Any other relevant sector-specific factors.

To inform the final stringency of the output-based standards, the Department developed a three-phased approach that took into account the factors listed above. The Department further refined its approach to voluntary participation to allow for earlier participation in the OBPS than originally proposed. The proposed treatment of electricity under the OBPS was also updated to encourage the decarbonization of electricity generation while mitigating electricity price impacts on businesses and households. A federal offset system is also being considered, whereby federal offset credits could be used for compensation under the OBPS.

Impacts by sector

Figure D below illustrates the OBPS compensation obligation as a percentage of the sector’s gross value added, compared to the same metric under the fuel charge regime. Gross value added is equivalent to the GDP of an individual producer, industry or sector, adjusting for subsidies and taxes on products. The “chemical, plastics, and rubber manufacturing,” “oil and gas extraction” and “non-metallic mineral product manufacturing” sectors have costs as a percentage of sector GVA that are negative (i.e. cost savings). These EC-PRO results are not fully aligned with the Department’s competitiveness analysis of historical facility level data due to differences in assumptions, and modelling of standards using emissions per dollar of output, while output-based standards are established based on emissions per physical unit of output, as discussed in the “Costs” section. The departmental competitiveness analysis suggests that at the outset of the OBPS, each sector at the provincial/territorial level would have a compensation requirement.

Figure D: Cost as a percentage of sector gross value added in 2022

Detailed information can be found in the surrounding text.

Some sectors have larger GVA impacts than others, largely due to an above-average amount of covered emissions. The Department adjusted the output-based standards of these sectors to minimize competitiveness risks to EITE facilities. The costs in Figure D only apply to backstop jurisdictions, which can lead to some discrepancies between these results and those used in the Department’s competitiveness analysis, which was conducted at the national level.

Impacts by region

By 2030, the Regulations are estimated to result in a cumulative increase in economic output of $11 billion in Canada compared to the Baseline Scenario in which the fuel charge applies to all industrial fuel use. Much of this increase in national economic output is expected to occur in the backstop jurisdictions where the OBPS applies (see Table 9). The majority of facilities covered by the OBPS are located in Ontario and Saskatchewan. Therefore, the economic impacts of the Regulations are concentrated in these provinces. The regional impacts are relative to the size of each jurisdiction’s economy.

Table 9: GDP impacts by backstop jurisdiction in 2022 associated with the application of the OBPS instead of applying the fuel charge to all industrial fuel use in backstop jurisdictions (millions of dollars)
Backstop jurisdiction	GDP impacts
Manitoba	25
New Brunswick	21
Nunavut	10
Ontario	345
Prince Edward Island	12
Saskatchewan	183
Yukon	3

Impacts by income level

Although the model does not account for income distribution, it is expected that the benefits to household welfare will not be uniformly distributed across the population. The OBPS will lead to increased output at covered facilities, which will lead to increased income for some owners of capital, and higher wages to some workers.

Uncertainty of impact estimates

The results of this analysis are based on key parameter estimates, which may be higher or lower than indicated by available evidence. Given this uncertainty, sensitivity analyses were conducted to assess the impact of changes to these parameters on the expected net benefits of the Regulations, where possible.

Voluntary participation: There is some uncertainty surrounding the number of voluntary participants as the model assumes that all facilities in covered sectors that produce a product or conduct an activity for which an output-based standard exists will opt into the OBPS to reduce their obligation to pay the fuel charge. Therefore, the impacts of the Regulations may be overestimated.

Carbon leakage: In the Baseline Scenario, there is an increased risk that domestic production shifts to foreign jurisdictions due to increased production costs attributable to the fuel charge. The extent to which these shifts in production lead to foregone foreign GHG emission reductions depends on the emissions intensities of the facilities where production is relocated, and the associated quantities of production, both of which are unknown. The Regulatory Scenario therefore only accounts for incremental foregone GHG emission reductions in Canada. However, it is likely that the domestic foregone GHG emission reductions would be offset to some extent by decreases in foreign emissions in the Regulatory Scenario. Therefore, the net costs associated with foregone GHG emission reductions are likely overestimated due to the scope of the analysis.

Household welfare and GHG emissions: Variables such as energy and fuel prices, and production forecasts contribute to uncertainty regarding estimates of changes in household welfare and GHG emissions resulting from the Regulations. However, changes in production, and thus household welfare, are highly correlated with changes in GHG emissions. Therefore, if household welfare increases (decreases), GHG emissions would likely increase (decrease) proportionally. While an overestimation of increases in household welfare would lead to a proportional decrease in net benefits, the ratio of benefits to costs would not be expected to change significantly.

Cost valuation: The values used to determine the costs associated with foregone domestic GHG reductions are subject to uncertainty. The Social Cost of GHGs is used to value future climate costs is generated using models that rely on forecasts of both natural and economic outcomes 50 to 300 years into the future, making these estimates inherently uncertain. To evaluate the impact of potential differences in the true values of these variables compared to the estimated values, the value of the costs attributed to the Regulations were estimated using 95th percentile Social Cost of GHGs estimates. This scenario would yield a net cost of $1.8 billion, as shown in Table 10 below. It is expected that some of the domestic GHG emissions that are emitted after the implementation of the OBPS would have likely been emitted outside of Canada in the baseline due to carbon leakage, because of the full application of the fuel charge. The OBPS is expected to reduce the risks of carbon leakage, thus the estimated costs of foregone emissions reductions are likely to be overestimated.

Discount rate: TBS recommends a 7% discount rate for cost-benefit analyses in most cases; however, when regulations have impacts occurring over a long time horizon, a lower discount rate (3%) is appropriate. A sensitivity analysis was done to compare the central analysis (3% discount rate) to the higher discount rate (7%), which still yields an expected net benefit of $1.6 billion, as shown in Table 10.^{footnote 59}

Table 10: Sensitivity analysis, cumulative 2019–2030 (millions of dollars)
Scenario	Benefits (B)	Costs (C)	Net Benefits (B-C)
Central analysis (from Table 8)	3,224	1,071	2,153
95th percentileNONBREAKING_SPACE–Social Cost of GHGs	2,587	4,434	−1,847
Discount rate 7%	2,417	848	1,569

Small business lens

To extend participation in the OBPS to smaller facilities, the Department developed the Voluntary Participation Policy for facilities located in backstop jurisdictions with reported annual emissions to the GHGRP for any year (starting with the 2017 reporting year) of at least 10 kt of CO₂e. In response to comments from smaller industrial facilities, which were not eligible for voluntary participation in the proposed design of the OBPS until 2020, the Department revised its approach to allow for participation in the OBPS starting in 2019.

No mandatory participants covered by the OBPS are considered small businesses. However, it is possible that some voluntary participants opting into the OBPS are small businesses. The costs incurred by voluntary participants due to the Regulations do not represent compulsory regulatory costs for small businesses, as these facilities have the discretion to choose between the fuel charge and participation in the OBPS. It is expected that any small business in a backstop jurisdiction that voluntarily participates in the OBPS is doing so in order to reduce their costs, relative to paying the fuel charge on fossil fuels they use at the facility. Thus, the OBPS is expected to benefit all covered facilities, including small business participants.

The OBPS is also designed to provide compliance flexibility, which will extend to voluntary participants, including small businesses. When the GHG emissions of a covered facility are above its annual limit, the facility will be required to provide compensation for its excess emissions (compliance obligation). The facility will have the following options to meet its compliance obligation:

Pay the excess emissions charge;
Submit compliance units (federal OBPS surplus credits, offset credits issued by the Minister (if enabled through regulations) and certain provincial and territorial GHG offset credits recognized as compliance units); or
Submit a combination of the previous two options.

“One-for-One” Rule

Administrative burden costs will increase due to the Regulations in comparison to the Baseline Scenario. There are 122 facilities in backstop jurisdictions that registered with the OBPS as mandatory facilities. The costs incurred by facilities in backstop jurisdictions that voluntarily opt into the OBPS do not represent compulsory costs due to the Regulations, as the persons responsible for the facilities would have the discretion to choose between the fuel charge regime and participation in the OBPS. Thus, the “One-for-One” Rule only applies to mandatory facilities in backstop jurisdictions.

In accordance with the Registration Notice, the mandatory facilities completed their registration under the OBPS prior to April 1, 2019. The registration costs incurred by these facilities are outlined in the Regulatory Impact Analysis Statement published for the Notice on October 31, 2018. Since these registration costs were incurred before the publication of the Regulations, they are outside the scope of this analysis. The GGPPA also requires participants in the OBPS to register with CRA and to provide monthly reports related to the fuel charge. As these costs are incurred under the GGPPA, they are also outside the scope of this analysis and are not included in the administrative burden cost calculations for the Regulations.

As of January 1, 2019, registered facilities are required to annually quantify their respective GHG emissions and production, using the methodologies prescribed in the Regulations that are specific to the activity listed in Schedule 1 of the Regulations carried out at the facility. There are also other data gathering requirements. As a result, there will be annual ongoing administrative costs for OBPS participants associated with the monitoring, gathering, and recording of information, including data relating to facilities’ production and GHG emission levels. The Regulations contain requirements concerning the preparation of annual reports and their associated verification, and the provision of the carbon price on a facility’s emissions above the limit to CRA as well.

The Regulations introduce administrative costs that are incremental to the costs that mandatory participants in backstop jurisdictions already incur due to existing GHGRP requirements and provincial GHG reporting requirements. For the 122 facilities that are required to participate in the OBPS, the additional administrative impacts per facility are estimated to be

20 hours in 2019 for learning activities for participants under the OBPS;
90 hours per year on average from 2019 to 2029, for information-gathering activities and the quantification of GHG emissions and production;
30 hours per year on average, from 2019 to 2029, for the preparation, approval and submission of the annual report;
56 hours per year on average, from 2020 to 2029, for internal and third-party verification activities associated with the annual report; and
7.5 hours per year on average, from 2020 to 2029 for the payment of the excess emissions charge or remittance of compliance units and submission of a compensation report.

The total annualized administrative costs for regulatees to comply with the regulatory requirements over a ten-year time frame (2019 to 2029) are approximately $592,657 or $4,858 per facility.^{footnote 60}

The Regulations are considered an “IN” under the “One-for-One” Rule given the expected increases in administrative costs resulting from the Regulations. Therefore, these cost increases will require equal and offsetting reductions in administrative costs. Since the Regulations are a new regulatory title, there will also be a requirement under the “One-for-One” Rule to repeal one existing regulatory title.

The Regulations will replace the two regulatory instruments that were published in the Canada Gazette, Part II, in fall 2018: the Registration Notice and the Information Order. The Minister will repeal these instruments under the Order Repealing Certain Legislative Instruments. The Order Repealing Certain Legislative Instruments will result in the repeal of the associated administrative burden; however, there will be administrative burden associated with the Regulations.^{footnote 61} The repeal of the Registration Notice and Information Order will be considered two titles OUT under Element B of the “One-for-One” Rule. Therefore, the “OUT” under this Rule is expected to be $553,660 and the annualized administrative costs per business is $4,163, based on expected administrative burden incurred by mandatory covered facilities from 2019 to 2029.^{footnote 62}

Regulatory cooperation and alignment

International

The Regulations do not directly relate to a work plan or a Government of Canada commitment under a formal international regulatory cooperation forum. However, the Regulations do relate to international agreements to combat climate change and adapt to its effects. Canada is working in partnership with the international community to implement the Paris Agreement, to support the goal to limit temperature rise this century to well below 2 °C and pursuing efforts to limit the temperature increase to 1.5 °C. 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.

As part of its commitments made under the Paris Agreement, Canada pledged to reduce national GHG emissions by 30% below 2005 levels by 2030. To meet this commitment, the Government of Canada is putting in place a series of measures, including the Pan-Canadian Approach to Pricing Carbon Pollution. The Regulations are a key component of this approach. Other countries are taking a variety of approaches, some of which include carbon pricing. The OBPS positively contributes to Canada’s overall goal of combatting climate change by incentivizing EITE facilities to lower their emissions intensity. A price incentive is applied to all emissions because covered facilities that emit below their annual emissions limit can earn surplus credits that they may sell or use to offset their future emissions.

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 a type of emissions trading system (ETS), in which baseline emission levels are defined for individual regulated facilities and credits may be issued to these entities if they have reduced their emissions below the allotted level (a “baseline-and-credit system”).^{footnote 63} The OBPS is one of several types of systems that can maintain a carbon price while helping protect against competitiveness and carbon leakage risks.

Similar output or production-based approaches to reduce costs for at-risk industries have been used successfully in carbon pricing systems in Canada and around the world. In Canada, these include Alberta’s Carbon Competitiveness Incentive Regulation, which takes a very similar approach to the federal OBPS, and Quebec’s cap-and-trade system, which provides free allowances based on historical emissions intensities and output. Most methods of assessing risks to competitiveness and carbon leakage use similar metrics, and find similar groups of sectors to be at highest risk. Differences between systems include the specific performance standards set for industrial sectors, compliance mechanisms, and details of definitions of sectors or facilities. As many as 57 other jurisdictions in the world, such as the state of California, the European Union, Mexico, China and the Republic of Korea, are planning to or have already implemented various forms of emissions-pricing regimes, including ETS.^{footnote 64}

Although not pursued at this time, the GGPPA enables the exchange of credits with other carbon markets, whether domestic or international. The Government of Canada, along with other Parties to the United Nations Framework Convention on Climate Change (UNFCCC), is engaged in discussions on ITMOs and non-market approaches to advance development of the guidance to implement the Paris Agreement. Once developed, this guidance would facilitate the exchange of credits and linkages with other carbon pricing systems. An amendment to the Regulations would be required to recognize any international credits as compliance units.

Domestic

The PCF, adopted by the Prime Minister and most First Ministers in December 2016 sets out a collective plan to reduce Canada’s GHG emissions, grow the economy and adapt to climate change. The Pan-Canadian Approach to Pricing Carbon Pollution and the Regulations comprise a central element of the PCF.

The Department recognizes equivalent carbon pricing systems in provinces and territories in Canada, when compared to the federal Benchmark. Provinces and territories were given the flexibility to implement the type of carbon pricing system that made sense for their circumstances; either an explicit price-based system (such as a carbon tax or carbon charge and performance-based emissions system) or cap-and-trade. As part of the federal Benchmark, the federal government also committed to a federal carbon pricing backstop that 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.

These backstop jurisdictions (Ontario, New Brunswick, Manitoba, Prince Edward Island, Saskatchewan, Yukon and Nunavut) were listed in Part 2 of Schedule 1 to the Act on October 19, 2018. To provide stability, these provinces and territories will remain in the backstop until 2022; however, the Minister may recommend to the Governor in Council to add jurisdictions to Part 2 of Schedule 1 to the Act as required. The PCF includes a commitment for a review of the overall approach to carbon pricing by early 2022 to confirm the path forward. An interim report will also be completed in 2020. The design of the OBPS may be adjusted in response to these reviews.

Regulatory overlap with non-backstop jurisdictions

Non-backstop jurisdictions such as British Columbia, Alberta, Quebec, Nova Scotia, Newfoundland and Labrador, and Northwest Territories are implementing a carbon pollution pricing system that sufficiently meets the federal Benchmark and thus are not subject to the federal backstop system.^{footnote 65} Alberta’s repeal of the carbon levy portion of its carbon pollution pricing system as of May 30, 2019, is a significant change and is being assessed against the federal stringency benchmark.

Strategic environmental assessment

The Regulations have been developed under the PCF, specifically the Pan-Canadian Approach to Pricing Carbon Pollution. The Regulations support the implementation of the PCF and the Pan-Canadian Approach to Pricing Carbon Pollution. A strategic environmental assessment (SEA) was completed for the PCF in 2016. The SEA concluded that proposals under the framework will reduce GHG emissions and are in line with the 2016–2019 Federal Sustainable Development Strategy. SEAs were completed for elements of carbon pollution pricing in May 2017, June 2018, September 2018 and October 2018. These assessments concluded that, although the Regulations are expected to lead to fewer domestic GHG emissions reductions relative to the fuel charge, the Regulations support the implementation of the PCF and reduce the risk of carbon leakage and competitiveness impacts. In combination with other measures outlined in the PCF, the federal carbon pollution pricing backstop system supports a number of Federal Sustainable Development Strategy goals, specifically the effective action on climate change, clean growth and clean energy.

Gender-based analysis plus (GBA+)

The OBPS component of the federal backstop system is expected to have an overall net positive economic impact across demographic groups as the system is designed to provide economic relief to EITE industries. The OBPS is also expected to mitigate adverse cost and competitiveness impacts and carbon leakage by generally providing relief from the fuel charge and pricing a facility’s emissions above a certain limit. In lieu of paying the carbon price on a facility’s emissions above the limit, the facility also has the option to compensate for excess pollution through the use of compliance units to ensure lowest cost compliance.

The specific OBPS impacts are contingent on the type of facility covered by the system, how proceeds are used, the price they will be required to pay and/or the number of surplus credits they may receive. All direct proceeds generated under the OBPS will be returned to the jurisdiction of origin to help further reduce GHG emissions. Further details on how the return of OBPS proceeds will be allocated will be outlined in 2019.

Employment status: Overall, the impacts on employment are expected to be lower under the OBPS than if industrial facilities were exposed to the full fuel charge. There may be some industrial facilities that will face a higher cost under the OBPS than the fuel charge; however, the Department took into account the competitiveness and carbon leakage risk for industries when determining the stringency of output-based standards to maintain the competitiveness of Canadian industry.
Gender: The lower risk of carbon leakage and related decreased risk of job loss may indirectly benefit more men than women, as men are typically a higher proportion of the labour force in EITE industries.
Indigenous communities: Impacts on Indigenous communities will be contingent on the backstop jurisdiction, how proceeds from the federal carbon pricing system are used, and the impacts of other investments and programs being implemented to facilitate the transition to cleaner energy and fuel options, improved energy efficiency, and investment in infrastructure. The exemption from the fuel charge of diesel used for electricity generation in remote communities and the exemption of the fuel charge of aviation fuels in the territories will help to reduce impacts on remote Indigenous communities, as would proposed funding for Indigenous communities from fuel charge proceeds. The OBPS may offer offset credit generation opportunities (voluntary reductions in non-regulated sectors) for Indigenous peoples. British Columbia has some examples of how economic opportunities may arise for some Indigenous communities as a direct result of carbon pollution pricing.
Geography: Facilities in rural communities often contribute to rural economies by providing high-paying salaries, municipal tax proceeds, and infrastructure investments. Reductions in production, salaries, and jobs in such facilities could potentially affect economic activity and population retention in rural communities. The OBPS benefits these facilities by reducing exposure to the carbon pollution price as compared to the fuel charge.
Age: When searching for new employment, older workers (especially ages 55–64) in Canada face barriers including: ageism; lack of education and access to training; difficulty finding and applying to jobs; health issues, work-life balance issues, and lack of workplace accommodations.^{footnote 66,}^{footnote 67,}^{footnote 68} Overall, the impacts on employment are expected to be lower under the OBPS than if facilities were exposed to the full fuel charge.

Implementation, compliance and enforcement, and service standard

Implementation

Implementation activities related to the Regulations centre around three key statutory obligations, details of which are described in these Regulations: registration, annual reporting, and provision of compensation (payment and/or credits).

Implementation activities build on current implementation of the registration component of the program which began in late 2018 with the publication of regulatory instruments, and the Voluntary Participation Policy. The Department developed and administers an electronic system through which applicants can apply to register in the OBPS and resources to review, assess and coordinate decisions related to registration.

The Department is developing a system through which regulatees will submit annual facility reports and verification reports, remit compensation or receive surplus credits. The Department is procuring a service provider to build and maintain a tracking system as required by the GGPPA. CRA will provide an electronic system to accept OBPS facilities’ payment of the excess emissions charge and the Department will work with CRA to ensure payments collected are counted against regulatees’ compensation obligations.

To support OBPS regulatees’ understanding of regulatory requirements and provide timely responses to inquiries, the Department will continue to make available a dedicated email address and telephone line. Compliance promotion activities with OBPS regulatees and industry associations will continue to occur through web-based and printed material, webinars and information sessions. The Department also plans to enter into agreements with the Standards Council of Canada and the American National Standards Institute to support those organizations’ accreditation of verifiers to the needs of the OBPS.

Results of performance measurement of these Regulations will be included in the annual reports to Parliament regarding implementation of the GGPPA, required under Part 4 of that legislation. For example, key indicators that will be used to measure performance include awareness of Regulations and associated requirements, annual compensation levels, and changes to industry emissions intensity.

Compliance and enforcement

The GGPPA contains provisions related to offences which include failing to comply with an obligation arising from the GGPPA and providing false or misleading information, and associated penalties. The Department, in accordance with its compliance and enforcement policies, will undertake implementation and enforcement actions as necessary.^{footnote 69}

When verifying compliance, enforcement officers will apply the principles found in the Compliance and Enforcement Policies developed by the Department. 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.

Service standards

The Department, in its administration of the regulatory program, will respond to registration, annual reporting, and compensation inquiries from the regulated community in a timely manner, taking into account the complexity and completeness of the request. The Department intends to develop service standards for decision-making related to applications for registration, as well as for issuance of surplus credits. The Department has already developed and issued registration guidance and intends to produce guidance materials to support the regulated community’s submission of required annual and verification reports. The Department will also provide guidance material on providing compensation for excess emissions when that is owed. The new guidance will include a description of the required information, along with format and steps to be followed.

Contacts

Katherine Teeple
Director
Federal Carbon Pricing System Division
Carbon Pricing Bureau
Environmental Protection Branch
Department of the Environment
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: ec.tarificationducarbonecarbonpricing.ec@canada.ca

Matthew Watkinson
Director
Regulatory Analysis and Valuation Division
Economic Analysis Directorate
Strategic Policy Branch
Department of the Environment
200 Sacré-Cœur Boulevard
Gatineau, Quebec
K1A 0H3
Email: ec.darv-ravd.ec@canada.ca

Footnotes

Footnote a

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

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Footnote b

S.C. 2018, c. 12, s. 196

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Footnote c

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

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Footnote 1

SOR/2017-109

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Footnote 2

Canada’s Changing Climate Report

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Footnote 3

Ibid.

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Footnote 4

Pan-Canadian Framework on Clean Growth and Climate Change

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Footnote 5

For more information, please see the Government of Canada’s website on the Paris Agreement.

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Footnote 6

Pan-Canadian Approach to Pricing Carbon Pollution

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Footnote 7

Greenhouse Gas Pollution Pricing Act

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Footnote 8

Order Amending Part 2 of Schedule 1 to the Greenhouse Gas Pollution Pricing Act

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Footnote 9

For further information, please see the Government of Canada’s webpage on the Output-Based Pricing System.

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Footnote 10

Notice Establishing Criteria Respecting Facilities and Persons and Publishing Measures

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Footnote 11

Greenhouse Gas Emissions Information Production Order. This Order was amended on December 11, 2018 under the Order Amending the Greenhouse Gas Emissions Information Production Order.

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Footnote 12

Notice of intent to make regulations under part 2 of the Greenhouse Gas Pollution Pricing Act

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Footnote 13

Greenhouse Gas Reporting Program

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Footnote 14

Estimate from the Department’s model, EC-PRO (refer to Modelling section for further information).

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Footnote 15

Refer to the Regulatory Coverage section for further information on mandatory and voluntary facility definitions.

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Footnote 16

The Alberta government elected in Spring 2019 has stated that it intends to replace the CCIR with a different pricing system. At present, however, the CCIR remains in place and the Government of Alberta has not formally provided details about the replacement system.

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Footnote 17

For more information, refer to the World Bank’s Carbon Pricing Dashboard: Map & Data

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Footnote 18

Activities are production-based activities that are representative of the given sector and are provided on Schedule 1 of the Regulations.

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Footnote 19

Policy regarding voluntary participation in the output-based pricing system

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Footnote 20

Update on the output-based pricing system: technical backgrounder

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Footnote 21

Over time, the Department intends to add new activities to Schedule 1 with a numerical output-based standard. Competitiveness assessments will be undertaken for these sectors at that time.

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Footnote 22

For covered facilities in Prince Edward Island, the beginning of the compliance period starts on the date of registration specified on the facility’s certificate issued under section 171 of the GGPPA.

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Footnote 23

A new facility will be exempt from the compensation obligation and will not be issued surplus credits if the covered facility has not completed two full calendar years of production following the date of first production.

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Footnote 24

The excess emissions charge is set at $20 per tonne of excess CO2e in 2019, increasing by $10 per tonne each year to $50 per tonne of excess CO2e emissions in 2022.

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Footnote 25

Offset credits represent GHG emission reductions or removal enhancements generated from voluntary, project-based activities that are not subject to pollution pricing and that would not have occurred based on legal requirements and standard practices. Each offset credit represents one tonne of CO2e.

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Footnote 26

Environmental Violations Administrative Monetary Penalties Act

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Footnote 27

Technical paper: federal carbon pricing backstop

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Footnote 28

Carbon pricing: regulatory framework for the output-based pricing system

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Footnote 29

Carbon pricing: Compliance options under the federal output-based pricing system

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Footnote 30

Proposal for the Output-Based Pricing System Regulations

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Footnote 31

Refer to the “Modelling” section for further information on ECCC’s EC-PRO model.

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Footnote 32

Cost-benefit analysis framework for an Output-Based Pricing System

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Footnote 33

For more information on the regulatory development process, please see the Pricing carbon pollution for large industry: backgrounder

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Footnote 34

In December 2018, Canada announced the Regulations Amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations to phase out traditional coal-fired electricity by 2030 as well as greenhouse gas regulations for natural gas-fired electricity.

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Footnote 35

In accordance with the rules to be agreed upon under the UNFCCC Paris Agreement.

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Footnote 36

Technical Update to Environment and Climate Change Canada’s Social Cost of Greenhouse Gas Estimates

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Footnote 37

This estimate includes voluntary and mandatory participants. The Department estimates the number of voluntary participants based on 2017 GHGRP data. Given the administrative costs and additional coverage of the OBPS, certain facilities may decide not to opt in, which can result in an overestimation of the number of total participants to the OBPS.

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Footnote 38

Totals may not sum due to rounding.

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Footnote 39

Canadian cost-benefit analysis guide

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Footnote 40

The metric used to monetize the emissions in this CBA is the Social Cost of GHGs, which estimates the monetary value in a given year of worldwide damage that will occur over the coming decades and centuries from emitting one additional tonne of a given greenhouse gas (values developed for carbon dioxide, nitrous oxide and methane). The estimates of the Social Cost of GHGs are based on the projected lifetime impacts of additional emissions into the future.

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Footnote 41

Recently commissioned, retrofitted or expanded facilities can also apply to participate as a covered facility if they demonstrate that they will emit at least 10 kt of CO₂e per year within at least one of the three calendar years following the date of first production.

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Footnote 42

Partial opt-in is assumed in the “food, beverage, and tobacco manufacturing” and “wood product manufacturing” sectors because most facilities emit below 10 kt of CO₂e annually or are engaged in activities where no standard may exist.

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Footnote 43

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” 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.”
(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.

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Footnote 44

The 2017 Reference Case was used to maintain continuity with carbon pollution pricing analysis that has supported the development of the GGPPA and the Climate Action Incentive (CIA) payments. For more information, please see “How we’re putting a price on carbon pollution.”

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Footnote 45

Canada’s 7th National Communication and 3rd Biennial Report to the United Nations

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Footnote 46

For more information, please see Budget 2017’s Annex 1 - Details of Economic and Fiscal Projections.

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Footnote 47

Canada’s Energy Future 2017

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Footnote 48

In reality, the “rebate” is not applied retroactively; it is incorporated into the balance owing or credits to be received at the end of the compliance period.

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Footnote 49

Starting with the 2017 reporting year, the GHGRP applies to all facilities in Canada that emit 10 kt of CO₂e or more per year. Prior to the 2017 reporting year, the GHGRP applied to all facilities in Canada that emitted 50 kt or more of CO₂e per year. The National Inventory Report contains Canada’s annual estimates of GHG emissions covering anthropogenic emissions by sources and removals by sinks. For more information, please refer to Canada’s official greenhouse gas inventory.

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Footnote 50

Guidelines for Preparing Economic Analysis

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Footnote 51

Boadway, Robin W. and Neil Bruce. “Welfare Economics.” Basil Blackwell Publisher Limited, Oxford, 1984.

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Footnote 52

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

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Footnote 53

The verification cost per facility is assumed to be $40,000, which is a conservative estimate. In cases where a material error is discovered in the data and information reported in the last five years, a verified corrected report must be submitted. A facility could therefore end up having to pay for verification activities more than once a year.

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Footnote 54

There are no verification costs accounted for in 2019, since annual reports and their accompanied verification reports are not required until June 1 of the year following each compliance period.

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Footnote 55

The non-rounded increase in industry verification costs was estimated at $104,204,310.

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Footnote 56

Reporting through Single Window: Environment and Climate Change Canada

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Footnote 57

Registering a facility to the Output-Based Pricing System

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Footnote 58

The implementation costs may vary depending on factors such as changes in backstop jurisdictions, staffing needs, and other factors that may arise once the Regulations are in force.

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Footnote 59

The Social Cost of GHGs discounts the value of future climate damages to the year the associated emissions occur, at a 3% discount rate. This analysis discounts this value from the date the emissions occur to present value at a 7% discount rate.

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Footnote 60

As per the Red Tape Reduction Regulations, these values are calculated using a 10-year time frame, discounted at 7% in 2012 dollars. The weighted average wage rate was assumed to be about $44 per hour in all cost calculations. The weighted average time per facility was estimated to be about 186 hours per facility per year.

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Footnote 61

The learning and registration-related costs incurred in 2018 are not included in the administrative cost calculation for the repeal because they are outside the scope of this analysis.

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Footnote 62

These values are calculated in constant 2012 dollars as per “One-for-One” Rule guidance.

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Footnote 63

For more information on types of carbon pricing, refer to the World Bank’s Carbon Pricing Dashboard: What is Carbon Pricing?

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Footnote 64

For more information, refer to the World Bank’s Carbon Pricing Dashboard: Map & Data.

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Footnote 65

For further information on the Benchmark and the summary of assessment of stringency against the Benchmark, refer to the Annex of the Regulatory Impact Analysis Statement for the Order Amending Part 2 of Schedule 1 to the Greenhouse Gas Pollution Pricing Act.

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Footnote 66

Statistics Canada (2008), First Results from the Survey of Older Workers, by Pignal, J., Arrowsmith, S., and Ness, A., page 20, Ottawa.

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Footnote 67

Statistics Canada (2018), Labour Force Survey, CANSIM Table 282-0004.

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Footnote 68

Federal/Provincial/Territorial Ministers Responsible for Seniors (2012), Age-Friendly Workplaces: Promoting Older Worker Participation, Human Resources and Skills Development Canada, Gatineau.

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Footnote 69

Environmental compliance and enforcement policies

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