Reduction in the Release of Volatile Organic Compounds (Storage and Loading of Volatile Petroleum Liquids) Regulations: SOR/2025-88

Canada Gazette, Part II, Volume 159, Number 7

Registration
SOR/2025-88 March 7, 2025

CANADIAN ENVIRONMENTAL PROTECTION ACT, 1999

P.C. 2025-298 March 7, 2025

Whereas, under subsection 332(1)^{footnote a} of the Canadian Environmental Protection Act, 1999 ^{footnote b}, the Minister of the Environment published in the Canada Gazette, Part I, on February 24, 2024, a copy of the proposed Reduction in the Release of Volatile Organic Compounds (Storage and Loading of Volatile Petroleum Liquids) Regulations, and persons were given an opportunity to file comments with respect to the proposed Regulations or to file a notice of objection requesting that a board of review be established and stating the reasons for the objection;

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

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

Therefore, Her Excellency the Governor General in Council, on the recommendation of the Minister of the Environment and the Minister of Health, makes the annexed Reduction in the Release of Volatile Organic Compounds (Storage and Loading of Volatile Petroleum Liquids) Regulations under subsection 93(1)^{footnote d}, section 286.1^{footnote e} and subsection 330(3.2)^{footnote f} of the Canadian Environmental Protection Act, 1999 ^{footnote b}.

Reduction in the Release of Volatile Organic Compounds (Storage and Loading of Volatile Petroleum Liquids) Regulations

Interpretation

Definitions

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

Act

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

ASTM

means ASTM International, formerly known as the American Society for Testing and Materials. (ASTM)

authorized official

means

• (a) in respect of an operator that is a corporation, an officer of the corporation who is authorized to act on its behalf;
• (b) in respect of an operator that is an entity other than a corporation, an individual who is authorized to act on its behalf; and
• (c) in respect of an operator who is an individual, that individual or another individual who is authorized to act on their behalf.

It includes a person who has been designated in writing as a delegate to an officer or individual referred to in paragraph (a), (b) or (c), as the case may be, as well as a person who has been appointed to a position in replacement of such a person. (agent autorisé)

design specifications

means documents and records relating to any equipment, instrument or monitoring device that establish how the equipment, instrument or monitoring device must be manufactured, constructed, used or maintained to achieve its intended function and level of performance, including technical data, engineering drawings, standards, material specifications, manufacturer specifications, commissioning checklists, data sheets, manuals and standard operating procedures. (spécifications de conception)

emissions control equipment

means any type of equipment – including a vapour control system, temporary vapour control system, internal floating roof or external floating roof or pressure-vacuum vent, as well as alternative emissions control equipment referred to in section 80 – that is used to limit VOC emissions from tanks and loading racks. (équipement de contrôle des émissions)

existing tank

means a tank that is in service on or before the day on which these Regulations come into force. (réservoir existant)

existing loading rack

means a loading rack that is in service on or before the day on which these Regulations come into force. (rampe de chargement existante)

existing vapour control system

means a vapour control system that is under construction or in service at the facility on or before the day on which these Regulations come into force. (système de contrôle des vapeurs existant)

external floating roof

means a floating roof that is installed in a tank without a fixed roof such that the upper surface of the floating roof is exposed to atmospheric conditions. (toit flottant externe)

facility

means any buildings, other structures and stationary equipment that are used in the storage or loading of volatile petroleum liquid and located on a single property or on several properties that have at least one operator in common, are connected by piping that transfers volatile petroleum liquid and are separated by a property boundary to property boundary distance of no more than 2 km. (installation)

fenceline monitoring program

means,

• (a) a standard, modified or alternative fenceline monitoring program that meets the requirements of the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector);
• (b) a fenceline monitoring program in accordance with section 60 of the Petrochemical - Industry Standard issued under Ontario Regulation 419/05 (Air Pollution – Local Air Quality); or
• (c) a fenceline monitoring program that meets all the requirements of the following methods published by the United States Environmental Protection Agency:
  • (i) Method 325A — Volatile Organic Compounds from Fugitive and Area Sources: Sampler Deployment and VOC Sample Collection, except that the sampling period may range between 13 and 15 days, and
  • (ii) Method 325B — Volatile Organic Compounds from Fugitive and Area Sources: Sampler Preparation and Analysis, except that all samples must be analyzed for benzene. (programme de surveillance du périmètre)

fixed roof

means a roof that is permanently attached to a tank. (toit fixe)

fixed roof tank

means a tank that is equipped with a fixed roof but is not equipped with an internal floating roof. (réservoir à toit fixe)

flare

means any type of combustion device without an enclosed combustion chamber, including a burn pit designed to burn liquids or mixtures of gases and liquids. (torchère)

floating roof

means a structure that floats on the surface of a liquid and whose purpose is to limit vapour loss of that liquid to the environment. (toit flottant)

gasoline

means

• (a) a fuel that is sold or represented as gasoline with a benzene concentration of less than or equal to 1.5% by volume; or
• (b) a petroleum distillate, or a mixture of petroleum distillates, oxygenates or additives, that is suitable for use in a spark ignition engine and has the following characteristics, as determined using the applicable test method listed in the National Standard of Canada standard CAN/CGSB-3.5-2021 entitled Automotive gasoline:
  • (i) a vapour pressure of at least 35 kPa,
  • (ii) an antiknock index of at least 80,
  • (iii) a distillation temperature at which 10% of the fuel has evaporated of not less than 35°C and not greater than 70°C,
  • (iv) a distillation temperature at which 50% of the fuel has evaporated of not less than 60°C and not greater than 120°C, and
  • (v) a benzene concentration of less than or equal to 1.5% by volume. (essence)

guide pole

means a structure that is placed in a tank equipped with a floating roof for the purpose of preventing the floating roof from rotating within the tank or for the purpose of monitoring or sampling the liquid inside the tank. (poteau de guidage)

high benzene loading rack

means a loading rack that is designated under paragraph 13(a) or used to load a volatile petroleum liquid with a benzene concentration greater than 20% by weight. (rampe de chargement de liquide à haute concentration en benzène)

high benzene tank

means a tank that is designated under paragraph 12(a) or contains a volatile petroleum liquid with a benzene concentration greater than 20% by weight. (réservoir de liquide à haute concentration en benzène)

inerted tank

means a tank that opens to the atmosphere only through a pressure-vacuum vent and that is supplied with a non-hydrocarbon inert gas such that the atmosphere inside the tank contains insufficient oxygen to support combustion. (réservoir inerté)

internal floating roof

means a floating roof that is installed in a tank with a fixed roof such that the upper surface of the floating roof is protected from atmospheric conditions. (toit flottant interne)

liquid

means any type of liquid, including volatile petroleum liquid. (liquide)

liquid leak

means a leak for which three drops of liquid per minute or more form at the source as measured from the average number of drops per minute observed visually over a period of three minutes. (fuite de liquide)

loading

means any transfer of a liquid into a vehicle tank or from a vehicle tank into a fixed roof tank. (chargement)

loading factor

means a numerical value that represents the level of VOC emissions from a loading rack. (facteur de chargement)

loading rack

means all of the stationary equipment used for loading liquids, including structures, loading arms, pumps, piping and instrumentation. (rampe de chargement)

lower explosive limit or LEL

means the lowest concentration of a combustible vapour in the air that may ignite at a given temperature and pressure. (limite inférieure d’explosivité ou LIE)

lower explosive limit percentage or LEL%

means the ratio of the observed concentration of a combustible vapour to the LEL of that vapour, expressed as a percentage. (pourcentage de la limite inférieure d’explosivité ou pourcentage LIE)

occupied building

means a structure located outside of a facility’s property boundary that is used as a residence, workplace, place of education, medical establishment, childcare establishment or social or community centre, including a mobile home or portable building, but does not include

• (a) other mobile structures such as a tent, trailer or houseboat;
• (b) structures in which persons are present for less than one hour per day; or
• (c) structures whose initial construction began after the day on which these Regulations first applied to the facility. (bâtiment occupé)

operator

, in respect of a facility, means

• (a) if there is one person who operates, has charge of, manages or controls the facility, that person;
• (b) if there is more than one person who operates, has charge of, manages or controls the facility, the person who, under a written agreement between all those persons, is designated to be the operator; and
• (c) if the persons referred to in paragraphs (a) and (b) cannot be identified, the owner of the facility. (exploitant)

petroleum

means

• (a) naturally occurring hydrocarbons, such as natural gas, natural gas condensate, crude oil or bitumen;
• (b) hydrocarbon derivatives of the substances referred to in paragraph (a), such as fuels, lubricating oils, petrochemicals or asphalt;
• (c) coal tar and coal tar distillates; or
• (d) synthetic or semi-synthetic analogues of the substances referred to in paragraphs (a) to (c). (pétrole)

petroleum processing equipment

means equipment that is used to physically or chemically separate, transform or modify petroleum, including a distillation column, reactor or coker, but does not include equipment used only for storing, handling or blending petroleum, such as a tank, loading rack, pump or pipeline. (équipement de traitement du pétrole)

population centre

means a population centre — as defined by Statistics Canada in its publication entitled Dictionary, Census of Population, 2021 — with a population greater than 20,000. (centre de population)

pressure-vacuum vent

means a device that permits the flow of gas to or from the environment in the event of excess pressure or vacuum inside a fixed roof tank.(évent à pression-dépression)

primary seal

means, as the case may be,

• (a) on a floating roof that has two or more rim seals, the rim seal that is mounted closest to the surface of the liquid; or
• (b) on a tank that has only one rim seal, that rim seal. (joint primaire)

qualified professional

means a scientist or technologist who specializes in an applied science or technology applicable to their duty or function, such as engineering, engineering technology or chemistry. (professionnel qualifié)

scheduled maintenance

means maintenance of equipment that is scheduled to be performed on or before a date known to the operator of a facility in order to

• (a) comply with the design specifications of the equipment;
• (b) adhere to a schedule or project plan established by the operator in respect of the equipment; or
• (c) ensure that the equipment complies with a regulatory requirement. (entretien prévu)

secondary seal

means any rim seal mounted above the primary seal on a floating roof that has two or more rim seals. (joint secondaire)

standard m³

, in respect of the volume of a fluid, means cubic metres, when the fluid’s volume is measured at a temperature of 15°C and an absolute pressure of 101.325 kPa. (m³ normalisé)

switch loading

means the loading of a liquid that is not a volatile petroleum liquid into a vehicle tank that previously contained a volatile petroleum liquid without, before the liquid is loaded, the vapours in the vehicle tank being purged to a vapour control system or the vehicle tank being washed with a liquid that is not a volatile petroleum liquid. (chargement en alternance)

tank

means a tank, vessel, reservoir or container that is used to contain liquids, regardless of its shape or material of construction, but does not include

• (a) a vessel that operates under pressure or as part of a closed system such that there are no expected releases to the environment while the vessel is operating under normal operating conditions, including when it is being filled or emptied and when ambient conditions are changing; or
• (b) a cavern, underground porous rock reservoir or geological formation where liquids are stored under pressure. (réservoir)

temporary vapour control system

means a vapour recovery system or vapour destruction system designed for temporary or mobile use. (système temporaire de contrôle des vapeurs)

vapour

means any vapour or gas containing VOCs, including vapour arising from volatile petroleum liquid. (vapeur)

vapour balancing system

means a vapour control system that conveys vapours displaced during loading operations from the receiving tank to the source tank and prevents them from being released to the environment. (système de retour en boucle des vapeurs)

vapour control system

means a system that is designed to capture all vapours emitted from tanks or during loading operations and prevent them from being released to the environment. (système de contrôle des vapeurs)

vapour destruction system

means a vapour control system that destroys vapours by combustion, thermal oxidation or other means, including systems in which vapours are combusted to produce useful heat or energy and systems in which vapours are combusted for the sole purpose of preventing their release to the environment. (système de destruction des vapeurs)

vapour leak

means any release of vapour other than a release for which the concentration of VOCs at the source is determined, using a portable monitoring instrument, to be less than

• (a) 10 000 parts per million by volume, if the release is detected on or before December 31, 2026; or
• (b) 1000 parts per million by volume, if the release is detected after December 31, 2026. (fuite de vapeur)

vapour pressure

means the absolute partial pressure exerted on the walls of a vessel containing a liquid by the gas molecules above that liquid, when the liquid and its vapour are in equilibrium. (pression de vapeur)

vapour recovery system

means a vapour control system that captures vapours for a use other than their immediate use to produce heat or energy at a facility, including a non-regenerative system that retains the vapours in a solid or liquid medium. (système de récupération des vapeurs)

vehicle

means a machine that is designed to be mobile, including a truck, railcar, ship, transport barge or trailer but is not designed or has not been modified to serve for the purposes of the permanent stationary storage of liquids. (véhicule)

vehicle tank

means a tank attached to or integrated into a vehicle, other than a tank that is exclusively used to supply fuel to the vehicle’s engine. (réservoir de véhicule)

vehicle-to-vehicle loading

means the loading of volatile petroleum liquids directly from one vehicle tank to another without the use of a loading rack. (chargement de véhicule à véhicule)

volatile organic compound or VOC

means a compound that participates in atmospheric photochemical reactions that is not excluded under item 60 of Part 2 of Schedule 1 to the Act. (composé organique volatil ou COV)

volatile petroleum liquid

means petroleum, or a mixture that contains petroleum, that

• (a) exists as a liquid at a temperature of 20°C and an absolute pressure of 101.325 kPa;
• (b) contains 10% or more volatile organic compounds by weight;
• (c) has a vapour pressure greater than 10 kPa or, if the benzene concentration is greater than 2% by weight, 3.5 kPa; and
• (d) is not a mixture of petroleum and ethanol that contains less than 10% petroleum by weight. (liquide pétrolier volatil)

Incorporation by reference

(2) Any document that is incorporated by reference in these Regulations is incorporated as amended from time to time.

Inconsistencies with these Regulations

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

Application

Application — facilities

2 (1) Subject to subsection (2), these Regulations apply to any facility that meets any of the following conditions:

• (a) the sum of the internal volume of all tanks at the facility that are used to store volatile petroleum liquids is greater than or equal to 500 m³;
• (b) the total volume of volatile petroleum liquid loaded at the facility exceeds 4000 standard m³ in a calendar year;
• (c) at least one tank at the facility has an internal volume greater than or equal to 5 m³ and is used to store a volatile petroleum liquid with a benzene concentration greater than 20% by weight; or
• (d) at least one tank at the facility has an internal volume greater than or equal to or greater than 100 m³and is used to store a volatile petroleum liquid with a vapour pressure greater than 76 kPa.

Exceptions

(2) These Regulations do not apply to the following facilities:

• (a) facilities where volatile petroleum liquids are stored or loaded exclusively for the purposes of retail fuel sales at the facilities;
• (b) facilities that extract petroleum from an underground geological deposit or reservoir;
• (c) facilities that perform primary processing of petroleum after its extraction from an underground geological deposit or reservoir to
  • (i) remove water, carbon dioxide, sulphur compounds or contaminants from the petroleum, or
  • (ii) separate the petroleum into gaseous and liquid streams;
• (d) facilities that store or load petroleum before it undergoes primary processing at a facility referred to in paragraph (c);
• (e) facilities that separate a petroleum feed into its individual components or fractions, if at least 90% by weight of the petroleum feed entering the facility exists as a vapour at a temperature of 20°C and an absolute pressure of 101.325 kPa;
• (f) offshore facilities that are located more than three nautical miles from shore;
• (g) facilities whose property boundary is located more than 100 km from any population centre, if
  • (i) the loading racks at the facility are never used to load volatile petroleum liquids with a benzene concentration greater than 2% by weight,
  • (ii) the sum of the internal volume of all tanks at the facility that are used to store volatile petroleum liquids is less than 10 000 m³,
  • (iii) the total volume of volatile petroleum liquid loaded at the facility does not exceed 30 000 standard m³ in a calendar year, and
  • (iv) the total volume of volatile petroleum liquids loaded at the facility does not exceed 2000 standard m³ in a day;
• (h) facilities where each tank used to store volatile petroleum liquids and each loading rack used to load volatile petroleum liquids is located more than 300 m from any occupied building, if
  • (i) the tanks at the facility are never used to store, and the loading racks at the facility are never used to load, volatile petroleum liquids with a vapour pressure greater than 76 kPa or a benzene concentration greater than 2% by weight,
  • (ii) the sum of the internal volume of all tanks at the facility that are used to store volatile petroleum liquids is less than 2000 m³,
  • (iii) the total volume of volatile petroleum liquid loaded at the facility does not exceed 25 000 standard m³ in a calendar year, and
  • (iv) the total volume of volatile petroleum liquid loaded at the facility does not exceed 500 standard m³ in a day; and
• (i) facilities where each tank used to store volatile petroleum liquids and each loading rack used to load volatile petroleum liquids is located more than 60 m from any occupied building, if
  • (i) the tanks at the facility are never used to store, and the loading racks at the facility are never used to load, volatile petroleum liquids with a vapour pressure greater than 76 kPa or a benzene concentration greater than 2% by weight,
  • (ii) the sum of the internal volume of all tanks at the facility that are used to store volatile petroleum liquids is less than 2000 m³,
  • (iii) the total volume of volatile petroleum liquid loaded at the facility does not exceed 20 000 standard m³ in a calendar year,
  • (iv) the total volume of volatile petroleum liquid loaded at the facility does not exceed 500 standard m³ in a day, and
  • (v) the volatile petroleum liquids are stored at the facility in either fixed roof tanks that are each less than 5 m in diameter and 150 m³ in volume or underground tanks of any size.

Upgrading facilities — application

3 For greater certainty, these Regulations apply to facilities that engage in the upgrading — by means involving distillation — of crude oil or bitumen, or of crude oil or bitumen that has been blended with other hydrocarbon compounds.

Distance of occupied building

4 (1) For the purposes of these Regulations, the distance between a tank or loading rack and an occupied building is the shortest distance between any part of the tank or loading rack that could be a source of VOC emissions and the perimeter of the occupied building.

Distance from population centre

(2) For the purposes of these Regulations, the distance between a facility and a population text-center is the shortest distance between the property boundary of the facility and the boundary of the population centre.

Non-application — equipment

5 (1) These Regulations apply to all tanks and loading racks at a facility other than

• (a) tanks with an internal volume of less than 5 m³;
• (b) tanks with an internal volume of less than 50 m³ that are never used to store gasoline or volatile petroleum liquids with a vapour pressure greater than 76 kPa or a benzene concentration greater than 2% by weight.
• (c) tanks that are attached to or integrated into a vehicle; and
• (d) tanks and loading racks that are subject to the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) and are equipped with a vapour control system that meets the requirements of those Regulations or, if those Regulations do not apply as a result of an agreement made under subsection 10(3) of the Act, a vapour control system that meets the requirements of the provisions referred to in that agreement.

Volume excluded

(2) If a tank or loading rack is exempted under subsection (1), the internal volume of the tank, or the volume of volatile petroleum liquid loaded with the loading rack, is not to be taken into account when determining, under subsection 2(1), whether these Regulations apply to the facility.

General Provisions

Identification of Equipment and Instruments

Identifier of equipment

6 (1) The operator of a facility must ensure that all tanks, loading racks and emissions control equipment at the facility are assigned identifiers.

Marking on equipment

(2) The operator must ensure that the identifiers are

• (a) marked on the tanks, loading racks and, if accessible to the operator, emissions control equipment;
• (b) recorded in asset management tools or electronic programs that are used to track inventory and maintenance of equipment; and
• (c) indicated on a site plan such that all tanks, loading racks and emissions control equipment can be identified at any time.

Identifier and marking of instruments

(3) The operator must ensure that each instrument used for the purposes of these Regulations is marked with an identifier.

Service Status

Tank

7 (1) A tank is

• (a) considered to be in service during any period in which it is used to store a volatile petroleum liquid;
• (b) considered to be not in service during any period in which it is not used to store a volatile petroleum liquid and, if it was previously in service, if it meets one of the conditions set out in subsection (2); and
• (c) considered to be not in service if the tank was emptied of all volatile petroleum liquids before the day on which these Regulations come into force and has not been used to store volatile petroleum liquids since it was emptied.

Tank — not in service

(2) A tank that was previously in service is considered to be not in service if

• (a) the interior of the tank has been cleaned to remove all volatile petroleum liquid, any sludge and any solid petroleum materials and the value of the LEL% inside the tank is less than 10 in the absence of mechanical ventilation; or
• (b) a liquid other than a volatile petroleum liquid has been introduced into the tank and
  • (i) testing of the liquid inside the tank indicates that it is not a volatile petroleum liquid, and
  • (ii) the value of the LEL% inside the tank is less than 10 in the absence of mechanical ventilation.

Loading rack

8 A loading rack is

• (a) considered to be in service during any period in which it is used to load a volatile petroleum liquid or is used for switch loading; and
• (b) considered to be not in service during any period in which it is not used to load any volatile petroleum liquid and is not used for switch loading.

Vapour control system

9 A vapour control system is

• (a) considered to be in service beginning on the day on which it is first used at a facility; and
• (b) considered to be not in service during any period in which its operation is interrupted in accordance with subsection 56(2).

Intermittent service tanks

10 (1) Subject to subsection (2), an operator may use up to three tanks at a single facility as intermittent service tanks. However, none of those tanks may be in service for more than 300 hours per calendar year.

Exceptions

(2) The operator must not use a high benzene tank, or a tank designated as a high volatility liquid tank under paragraph 12(b), as an intermittent service tank.

Analysis — variation in properties

(3) For the purposes of subsection (1), if the properties of the liquid contained in a tank vary such that the liquid is considered to be a volatile petroleum liquid at certain times, the operator must ensure that a statistical or engineering analysis is conducted to demonstrate that the tank will be in service for 300 hours or less per calendar year.

Exempt from requirements

(4) A tank that is used as an intermittent service tank is exempt from the requirements set out in sections 39 and 40.

Surge tanks

11 (1) Subject to subsection (2), an operator may use a tank as a surge tank if it is used only for the temporary storage of liquids transferred from a pipeline or petroleum processing equipment under abnormal operating conditions.

Exception

(2) The operator must not use a high benzene tank as a surge tank.

Liquids

(3) The operator must remove any liquid transferred into a tank that is used as a surge tank as soon after the transfer as the circumstances permit.

Exempt from requirements

(4) A tank that is used as a surge tank is exempt from the requirements set out in sections 39 and 40.

Designation

Tanks

12 The operator of a facility must designate each tank that is in service at the facility as belonging to one of the following categories:

• (a) high benzene tank, in which case the tank may contain any volatile petroleum liquid;
• (b) high volatility liquid tank, in which case the tank may only contain a volatile petroleum liquid whose benzene concentration does not exceed 20% by weight;
• (c) volatile petroleum liquid tank, in which case the tank may only contain a volatile petroleum liquid whose vapour pressure does not exceed 76 kPa and benzene concentration does not exceed 20% by weight; or
• (d) small volatile petroleum liquid tank, in which case the tank
  • (i) must have an internal volume of less than 150 m³ or, if the tank is in the form of a vertically oriented cylinder capable of accommodating a floating roof, an internal diameter of less than 5 m, and
  • (ii) may only contain a volatile petroleum liquid whose vapour pressure does not exceed 76 kPa and benzene concentration does not exceed 20% by weight.

Loading racks

13 The operator of a facility must designate each loading rack that is used at the facility to load volatile petroleum liquids as belonging to one of the following categories:

• (a) high benzene loading rack, in which case the loading rack may be used to load any volatile petroleum liquid;
• (b) volatile petroleum liquid loading rack, in which case the loading rack may only be used to load a volatile petroleum liquid whose benzene concentration does not exceed 20% by weight;
• (c) low throughput loading rack, in which case the loading rack may only be used to load a volatile petroleum liquid if the benzene concentration does not exceed 20% by weight and if either
  • (i) the loading rack and any fixed roof tank that receives volatile petroleum liquid from the loading rack are located more than 300 m from any occupied building and the following loading factors do not exceed 1:
    • (A) the total loading factor of the facility, and
    • (B) the maximum daily loading factor of the facility, or
  • (ii) the loading rack is located more than 50 km from any population centre and more than 1.5 km from any occupied building and the following loading factors do not exceed 2:
    • (A) the total loading factor of the facility and
    • (B) the maximum daily loading factor of the facility, or
  • (iii) the loading factor of the loading rack does not exceed 0.04; or
• (d) remote loading rack, in which case the loading rack may only be used to load a volatile petroleum liquid if the vapour pressure of that liquid does not exceed 76 kPa, the benzene concentration of that liquid does not exceed 0.5% by weight and the loading rack is located more than 50 km from any population centre and more than 1.5 km from any occupied building.

Designation process

14 An operator must designate the category of a tank or loading rack by recording the designation in the inventory established under section 108 and indicating the category in the records maintained under section 110 or 112, as applicable.

Internal Volume of Tank

Internal volume

15 (1) The internal volume of a tank is the sum of the volumes of each space inside the tank that may be occupied by a volatile petroleum liquid.

Connected tanks

(2) Two or more tanks connected by a shared space or piping through which vapour may flow and that is not kept closed or isolated under normal operating conditions are considered to be a single tank with an internal volume equal to the sum of the internal volumes of the tanks and the internal volume of the shared space or piping.

Tank with separate compartments

(3) If a compartment of a tank is sealed to prevent entry of vapour and liquid from elsewhere in the tank, that compartment is considered to be a separate tank with a separate internal volume.

Floating roof or variable internal volume

(4) The internal volume of a tank that is equipped with an internal floating roof or external floating roof or that has a variable internal volume must be calculated at the highest design liquid fill level of the tank.

Loading

Loading factors

16 (1) The loading factor, the total loading factor and the maximum daily loading factor of a facility must be calculated in accordance with Schedule 1.

Exceptional event

(2) If an authorized official determines that the volume of volatile petroleum liquids loaded with a loading rack was increased temporarily due to an exceptional event that was not the result of scheduled maintenance that is under the control of the operator and determines that the operator minimized the duration and increase in volume loaded during the event to the extent possible, the calculation of the loading factor may be modified in accordance with item 1(c)(iv) of Schedule 1.

Vehicle-to-vehicle loading

17 (1) The operator of a facility must reduce the frequency of vehicle-to-vehicle loading at the facility to a minimum.

Safe location

(2) The operator must ensure that vehicle-to-vehicle loading is performed in a safe location as far away as possible from occupied buildings.

Sampling and Testing

Operator Responsibility

Requirements

18 The operator must ensure that sampling and testing conducted for the purposes of these Regulations are conducted in accordance with sections 19 to 29.

Properties of Liquids

Immiscible phases

19 (1) For the purposes of these Regulations, VOC concentration, vapour pressure or benzene concentration of a liquid with multiple immiscible phases is the highest value of the VOC concentration, vapour pressure or benzene concentration of any single immiscible phase of the liquid.

Samples

(2) If it is impossible to determine the value referred to in subsection (1), one of the following samples must be used:

• (a) if an immiscible phase is not present in a large enough quantity to form a separate layer from another more abundant phase, a well-mixed sample of both phases together; or
• (b) if an immiscible phase forms a stable emulsion in another phase and a sample of the pure phase cannot be obtained, a sample of the emulsion.

Gasoline

20 For the purposes of these Regulations, all gasoline is considered to have a VOC concentration of 100% by weight, a vapour pressure of 65 kPa and a benzene concentration of 1% by weight.

Methods for Sampling Liquids

Sampling method included

21 (1) If the applicable test methods referred to in sections 23 to 25 or an accepted alternative test method includes methods for sampling liquids, an operator must use one of those sampling methods.

Sampling method not included

(2) If the applicable test methods referred to in sections 23 to 25 or an accepted alternative test method do not include a method for sampling liquids, the sampling of liquids must be performed in accordance with one of the following sampling methods:

• (a) the method set out in the standard ASTM D3700–21, entitled Standard Practice for Obtaining LPG Samples Using a Floating Piston Cylinder;
• (b) the method set out in the standard ASTM D8009–22, entitled Standard Practice for Manual Piston Cylinder Sampling for Volatile Crude Oils, Condensates, and Liquid Petroleum Products; or
• (c) the method set out in standard ASTM D4057–22, entitled Standard Practice for Manual Sampling of Petroleum and Petroleum Products.

Crude oil and other

(3) Despite subsection (2), the sampling of crude oil, natural gas condensate and other naturally occurring petroleum and the sampling of other liquids that are known or suspected to contain hydrocarbon components that exist as a vapour under ambient conditions must be performed in accordance with the method referred to in paragraph (2)(a).

Insufficient pressure

(4) Despite subsections (2) and (3), if the pressure at the sampling point is insufficient to permit sample collection, the sampling must be performed in accordance with the method referred to in paragraph (2)(b).

Liquid too viscous

(5) Despite subsections (2), (3) and (4), if the liquid is too viscous to permit sample collection, the sampling must be performed in accordance with the method referred to in paragraph (2)(c).

Sample containers

(6) Sample containers must remain sealed after the sample is collected and may be opened only for testing in accordance with the applicable testing method.

Qualified professional

22 All sampling must be performed by one of the following persons:

• (a) a qualified professional;
• (b) a person supervised by a qualified professional; or
• (c) a person who has, not more than 12 months before the first time that they perform sampling, received training on the relevant sampling methods for the purposes of these Regulations from a qualified professional.

Test Methods

Vapour pressure

23 (1) The vapour pressure of a liquid must be determined in accordance with one of the following test methods:

• (a) the method ASTM D2879–23, entitled Standard Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope; or
• (b) the method ASTM D6377–20, entitled Standard Test Method for Determination of Vapor Pressure of Crude Oil: VPCRx (Expansion Method).

Limitation

(2) The test method referred to in paragraph (1)(a) may be used only to measure the vapour pressure of a liquid that consists of a single chemical species or of a single chemical species with an amount of impurities that is acceptable for general commercial trade.

Vapour-liquid ratio

(3) A vapour-liquid ratio of 4:1 must be used to determine the vapour pressure of a liquid in accordance with the test method referred to in paragraph (1)(b).

Temperature

(4) The following temperatures must be used to determine the vapour pressure of a liquid in accordance with one of the test methods referred to in subsection (1):

• (a) if the liquid is at ambient temperature, 20°C; and
• (b) if the liquid is artificially heated or cooled, the highest monthly average operating temperature observed during the preceding 12 months.

Benzene concentration

24 The benzene concentration of a liquid must be determined in accordance with one of the following test methods:

• (a) the method ASTM D3606–24a, entitled Standard Test Method for Determination of Benzene and Toluene in Spark Ignition Fuels by Gas Chromatography;
• (b) the method ASTM D4367–22, entitled Standard Test Method for Benzene in Hydrocarbon Solvents by Gas Chromatography;
• (c) the method ASTM D5134–21, entitled Standard Test Method for Detailed Analysis of Petroleum Naphthas through n-Nonane by Capillary Gas Chromatography;
• (d) the method ASTM D5580–21, entitled Standard Test Method for Determination of Benzene, Toluene, Ethylbenzene, p/m-Xylene, o-Xylene, C9 and Heavier Aromatics, and Total Aromatics in Finished Gasoline by Gas Chromatography;
• (e) the method ASTM D5769–22, entitled Standard Test Method for Determination of Benzene, Toluene, and Total Aromatics in Finished Gasolines by Gas Chromatography/Mass Spectrometry;
• (f) the method ASTM D6229–06, entitled Standard Test Method for Trace Benzene in Hydrocarbon Solvents by Capillary Gas Chromatography;
• (g) the method ASTM D7504–23, entitled Standard Test Method for Trace Impurities in Monocyclic Aromatic Hydrocarbons by Gas Chromatography and Effective Carbon Number; or
• (h) the method National Standard of Canada CAN/CGSB-3.0 No. 14.3-2022, entitled Methods of testing petroleum and associated products: Standard test method for the identification of components in automotive gasoline using gas chromatography.

VOC concentrations — liquids

25 (1) Subject to subsection (2), the VOC concentration of a liquid must be determined in accordance with one of the following test methods:

• (a) the method set out in the standard ASTM E169–16, entitled Standard Practices for General Techniques of Ultraviolet-Visible Quantitative Analysis; or
• (b) the method set out in the standard ASTM E260–96, entitled Standard Practice for Packed Column Gas Chromatography.

Oil-water mixture

(2) If the liquid is an oil-water mixture, its VOC concentration may be determined by any method that conforms to generally accepted engineering practices, including a method that involves the use of physical simulation or the application of standards or supplier specifications.

VOC concentrations — vapour

26 (1) An instrument used to determine the presence of VOCs in vapour form, including for the purpose of detecting vapour leaks, must be of one of the following types:

• (a) a portable monitoring instrument that meets the requirements set out in subsection 5(1) of the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector);
• (b) an optical gas-imaging instrument that meets the requirements set out in subsections 5(2) and (3) of those Regulations; or
• (c) a combustible gas detector that uses a catalytic bead sensor and meets the requirements set out in section 28 of these Regulations.

Instruments — LEL%

(2) An instrument used to determine an LEL% must be of the type referred to in paragraph (1)(a) or (c).

Instruments — emission of gas or vapour

(3) An instrument used to determine whether a release of a vapour is a vapour leak must be of the type referred to in paragraph (1)(a).

Equivalent VOC concentration

(4) If an LEL% is calculated from a measurement obtained with a portable monitoring instrument that produces a result in units of volume concentration, a VOC concentration of 140 parts per million by volume is considered to equal an LEL% of 1.

Instruments – use and calibration

27 Any instrument referred to in these Regulations must be used and calibrated in accordance with its design specifications.

Combustible gas detector — requirements

28 (1) A combustible gas detector that uses a catalytic bead sensor must meet the following requirements:

• (a) each day before it is used, it must be calibrated in accordance with its design specifications using output correction factors, if necessary, and a calibration gas that are appropriate for the expected vapour composition;
• (b) it must produce an output directly as an LEL%;
• (c) it must have an output range that spans an LEL% of at least 1 to 100; and
• (d) it must have an output accuracy that is within plus or minus 5% of a reading or plus or minus LEL% of 2, whichever value is greater, when used with the expected vapour composition.

Combustible gas detector — environment

(2) A combustible gas detector that uses a catalytic bead sensor must not be used in the following environments:

• (a) an atmosphere that contains less than 10% oxygen by volume;
• (b) an atmosphere that contains substances that are likely to poison the catalyst; or
• (c) any other environment in which, according to the design specifications of the combustible gas detector, the detector may not provide an accurate output.

Qualified professional

29 All testing required under sections 23 to 25 must be performed by one of the following persons:

• (a) a qualified professional;
• (b) a person supervised by a qualified professional; or
• (c) a person who has, not more than 12 months before the first time that they perform testing, received training from a qualified professional on the testing methods that are relevant for the purposes of these Regulations.

Alternative Test Methods

Application to the Minister

30 (1) An operator may apply to the Minister to use an alternative test method to those required under sections 23 to 25 for one of the following purposes:

• (a) to test a substance with properties that fall outside the scope of applicability of the required test methods;
• (b) to perform automated or continuous testing that cannot be accomplished using any of the required test methods; or
• (c) to achieve accuracy or precision that is superior to that of one of the required test methods.

Conditions

(2) The alternative test method must

• (a) measure the same physical properties as one of the test methods required under sections 23 to 25; and
• (b) for all cases in which it would be used, be equivalent or superior to, including in precision and accuracy, one of the test methods required under sections 23 to 25.

Equivalency

(3) For the purposes of paragraph (2)(b), the operator must determine the equivalency of the alternative test method in accordance with one of the following test methods:

• (a) the method set out in the standard ASTM D3764–23, entitled Standard Practice for Validation of the Performance of Process Stream Analyzer Systems; or
• (b) the method set out in the standard ASTM D6708–24, entitled Standard Practice for Statistical Assessment and Improvement of Expected Agreement Between Two Test Methods that Purport to Measure the Same Property of a Material.

Time limit

(4) The application must be submitted at least 60 days before the day on which the alternative test method is to be used.

Contents of application

(5) The application must contain the information referred to in Schedule 2 and may be submitted in respect of more than one of the operator’s facilities.

Clarifications or additional information

(6) The Minister may, on receiving the application, require that the applicant provide any clarifications or additional information that is necessary for the Minister to consider the application.

Acceptance of alternative test method

31 (1) If the Minister determines that the alternative test method meets the conditions set out in subsection 30(2), the Minister may accept the use of the alternative test method and must notify the applicant in writing of the decision, of any conditions of use of the method and of the situations in which the use of the method is permitted.

Use of method

(2) The applicant may begin using the alternative test method only after receipt of the notice of acceptance from the Minister.

Records

(3) An operator whose application to use an alternative test method has been accepted must maintain all records and supporting documents relating to the application.

Rejection of application

(4) The Minister must reject the application and must notify the applicant of that decision if

• (a) the Minister determines that the alternative test method does not meet the conditions set out in subsection 30(2); or
• (b) the information required under subsection 30(5) has not been provided or is insufficient to enable the Minister to consider the application.

Publication of accepted alternative methods

32 (1) The Minister may publish a list of accepted alternative test methods, including the conditions of use of the methods and the situations in which their use is permitted.

Use of accepted alternative test method

(2) An operator may use an accepted alternative test method that is on the list published under subsection (1) and, if they do so, they must maintain records and any supporting documents that demonstrate that the conditions for the use of the accepted alternative test method have been met.

VOC Emissions Control

Emissions Control Equipment

Emissions control equipment

33 (1) The operator of a facility must ensure that any tank at the facility that must be designated under section 12 and any loading rack at the facility that must be designated under section 13 is equipped with emissions control equipment in accordance with the requirements set out in sections 38 to 42, as applicable.

Compliance

(2) The operator must ensure that the emissions control equipment meets the requirements with respect to design and operation set out in sections 50 to 79 and the requirements with respect to inspection, testing and repair set out in sections 86 to 106, as applicable.

Internal floating roof

(3) Despite subsection (2), if a tank designated under section 12 is equipped with a vapour control system and an internal floating roof, the operator is not required to ensure that the internal floating roof meets the applicable requirements referred to in subsection (2).

Not in service

34 (1) Despite subsections 33(1) and (2), during a period when a tank or loading rack is not in service, sections 38 to 42 and 50 to 79 do not apply to that tank or loading rack.

Delay or omissions of inspections or tests

(2) During a period when a tank or loading rack is not in service, an operator may delay or omit the inspections referred to in sections 86 and 91, subsection 93(1) and sections 94 to 96 and 104, the tests referred to in sections 87 to 89 and the measurement referred to in section 97 until 30 days after the tank or loading rack is returned to service.

Repairs

(3) Despite any repair timelines established in sections 100, 101, 105 and 106, an operator must repair defects that are present when the tank or loading rack is not in service before the tank or loading rack is returned to service.

Required training

35 The operator of a facility must ensure that the emissions control equipment at the facility is operated, maintained, inspected and repaired only by a person who has, not more than 12 months before the first time that they operate, maintain, inspect or repair the emissions control equipment, received training on

• (a) the safe operation, maintenance and calibration of the emissions control equipment and, if applicable, leak detection instruments; and
• (b) the applicable requirements of these Regulations.

Flare

36 The operator of a facility may use a flare as a vapour control system only if it meets one of the following conditions:

• (a) the flare is in service at the facility before the day on which these Regulations come into force, or under construction on that day, and is used to control emissions from a tank that is not a high benzene tank or loading rack that is not a high benzene loading rack; or
• (b) the flare is used only for limited periods to receive excess vapours when flowrates exceed the capacity of the primary vapour control system or the primary vapour control system is inoperative.

Tanks

Emissions control equipment

37 The operator of a facility must ensure that each tank at the facility is designed, operated and maintained in a manner that allows for the effective operation of the emissions control equipment that is installed on that tank.

Vapour control system

38 Subject to section 44, the operator of a facility must ensure that each tank at the facility that is a high benzene tank or is designated as a high volatility liquid tank under paragraph 12(b) is equipped with a vapour recovery system or vapour destruction system.

Volatile petroleum liquid tank

39 The operator of a facility must ensure that each tank at the facility that is designated as a volatile petroleum liquid tank under paragraph 12(c) is equipped with at least one of the following:

• (a) a vapour recovery system;
• (b) a vapour destruction system;
• (c) an internal floating roof; or
• (d) an external floating roof.

Small volatile petroleum liquid tank

40 The operator of a facility must ensure that each tank at the facility that is designated as a small volatile petroleum liquid tank under paragraph 12(d) is equipped with at least one of the following:

• (a) a vapour recovery system;
• (b) a vapour destruction system;
• (c) an internal floating roof;
• (d) an external floating roof; or
• (e) a pressure-vacuum vent.

Position of liquid inlet

41 An operator must ensure that the liquid inlet of a tank designated under section 12 is positioned such that liquid enters the tank no more than 15 cm above the bottom of the tank unless

• (a) the tank is equipped with a vapour control system;
• (b) the liquid level in the tank always remains above the inlet during normal operation; or
• (c) the tank is an existing tank.

Loading Racks

Vapour control systems

42 The operator of a facility must ensure that each loading rack at the facility that is a high benzene loading rack or is designated as a volatile petroleum liquid loading rack under paragraph 13(b) is equipped with one of the following vapour control systems:

• (a) a vapour recovery system, a vapour destruction system or a vapour balancing system, in the case of a loading rack at a facility where all volatile petroleum liquids loaded, are fuels that are stored either in fixed roof tanks that each have an internal volume of less than 150 m³ or, if the tanks are in the form of a vertically oriented cylinder capable of accommodating a floating roof, an internal diameter of less than 5 m, or in underground tanks of any size;
• (b) a vapour recovery system, in the case of a loading rack that is used to load gasoline to trucks at a facility where more than 250 000 standard m³ per year of gasoline is loaded per calendar year and that was not equipped with an existing vapour destruction system on the day on which these Regulations came into force; and
• (c) a vapour recovery system or vapour destruction system, in any other case.

Temporary Vapour Control System

Temporary vapour control system

43 (1) An operator may use a temporary vapour control system on a tank or loading rack instead of the emissions control equipment required under section 38, 39, 40 or 42, as the case may be, during the following time periods:

• (a) if the requirements set out in those sections do not, under sections 135 and 136, apply to the tank or the loading rack on the day on which these Regulations come into force, or if the tank or loading rack has been designated as a deferred application tank or loading rack under section 125, a period not exceeding one year beginning on the day on which section 38, 39, 40 or 42 begins to apply to the tank or loading rack;
• (b) if the emissions control equipment requires scheduled maintenance or is to be replaced, a period not exceeding 180 days;
• (c) if a defect of the emissions control equipment is detected and the temporary vapour control system is used under paragraph 90(1)(b) or 101(2)(b), a period not exceeding one year;
• (d) if a defect of the emissions control equipment is detected and the temporary vapour control system is used under paragraph 100(1)(b), for the repair period referred to in that paragraph; and
• (e) in the case of a tank, the period during which the tank’s interior is being cleaned or the tank is being emptied until the tank is no longer in service.

Indefinite period of time

(2) If the requirements of subsection 53(2) and section 57 are met with respect to the temporary vapour control system, the operator may use it for an indefinite period instead of the applicable period referred to in any of paragraphs (1)(a) to (d).

Obligation to use

(3) An operator must use a temporary vapour control system during the following periods:

• (a) the period during which any of the activities referred to in paragraphs 49(1)(a) to (c) are being carried out, if the high benzene tank in question has not been equipped with a vapour control system or its vapour control system is inoperable;
• (b) the period during which a vapour control system that is being used to control emissions from a high benzene tank is inoperable due to scheduled maintenance; and
• (c) the period during which a vapour control system that is being used to control emissions from a high benzene loading rack is inoperable and that loading rack is being used to load a volatile petroleum liquid with a benzene concentration greater than 20% by weight.

High Benzene Tanks

Existing High Benzene Tanks

Use of floating roof

44 (1) Subject to subsections (2) and (3), the operator of a facility may continue to use an internal floating roof or external floating roof instead of a vapour control system to control VOC emissions from any existing high benzene tank at the facility that contained a liquid with a benzene concentration greater than 20% by weight on the day on which these Regulations come into force or during the period of one year that precedes that day if

• (a) the tank is located more than 300 m from any occupied building;
• (b) the tank is equipped with an internal floating roof or external floating roof that was installed before the day on which these Regulations come into force and that is free from the defects referred to in paragraphs 100(5)(d) and 101(1)(a); and
• (c) the operator of the facility has established a fenceline monitoring program at the facility, the benzene concentration measured at every sampling location of the fenceline monitoring program is less than or equal to the values set out in subsection 45(1) and the arithmetic average of the benzene concentration measured at every sampling location of the fenceline monitoring program in respect of that facility is less than or equal to the applicable value set out in subsection 45(2).

External floating roof — non-application

(2) Subsection (1) ceases to apply in respect of existing high benzene tanks equipped with external floating roofs on the seventh anniversary of the day on which these Regulations come into force.

Interim Order

(3) Subsection (1) does not apply in respect of existing high benzene tanks located at a facility that was subject to the Interim Order Respecting Releases of Benzene from Petrochemical Facilities in Sarnia, Ontario, made by the Minister on May 16, 2024 and published in Part 1 of the Canada Gazette on May 21, 2024.

Fenceline monitoring program

45 (1) For the purposes of paragraph 44(1)(c), the benzene concentrations measured in at least 24 of the 26 most recent sampling periods must be less than or equal to the following values:

• (a) in the case of a sampling period that ends before the first anniversary of the day on which these Regulations come into force, 19 μg/m³;
• (b) in the case of a sampling period that ends on or after the first anniversary of the day on which these Regulations come into force but before the second anniversary of that day, 17 µg/m³;
• (c) in the case of a sampling period that ends on or after the second anniversary of the day on which these Regulations come into force but before the third anniversary of that day, 15 µg/m³; and
• (d) in the case of a sampling period that ends on or after the third anniversary of the day on which these Regulations come into force, 13 µg/m³.

Arithmetic average

(2) For the purposes of paragraph 44(1)(c), the arithmetic average of the benzene concentrations measured for the 26 most recent sampling periods must be less than or equal to the following values:

• (a) if the most recent sampling period ends before the first anniversary of the day on which these Regulations come into force, 6.5 µg/m³;
• (b) if the most recent sampling period ends on or after the first anniversary of the day on which these Regulations come into force but before the second anniversary of that day, 5.5 µg/m³;
• (c) if the most recent sampling period ends on or after the second anniversary of the day on which these Regulations come into force but before the third anniversary of that day, 4.5 µg/m³; and
• (d) if the most recent sampling period ends on or after the third anniversary of the day on which these Regulations come into force, 3.5 µg/m³.

Excluded data

(3) For the purposes of paragraph 44(1)(c), the operator must exclude data collected during

• (a) sampling periods that ended before the ones for which data is included in the report submitted to the Minister under subsection 47(2);
• (b) sampling periods that ended before the day on which the operator equipped an existing high benzene tank at the facility with a vapour control system in accordance with section 38 and the first two sampling periods that ended after that day, if the arithmetic average of the benzene concentrations measured at every sampling location of the fenceline monitoring program in respect of that facility for the third to the eighth sampling periods that ended after that day was less than or equal to the following values:
  • (i) if the eighth sampling period ends before the first anniversary of the day on which these Regulations come into force, 6.5 µg/m³;
  • (ii) if the eighth sampling period ends on or after the first anniversary of the day on which these Regulations come into force but before the second anniversary of that day, 5.5 µg/m³;
  • (iii) if the eighth sampling period ends on or after the second anniversary of the day on which these Regulations come into force but before the third anniversary of that day, 4.5 µg/m³; and
  • (iv) if the eighth sampling period ends on or after the third anniversary of the day on which these Regulations come into force, 3.5 µg/m³; and
• (c) sampling periods that the Minister indicated under subsection 48(2) must be excluded.

Excluded data — arithmetic average

(4) When calculating the arithmetic average referred to in subsection (2), if the operator excludes data under subsection (3), the benzene concentration measured for each excluded sampling period at every sampling location must be replaced by the applicable value set out in paragraphs (2)(a) to (d) for the year in which the most recent included sampling period ended.

Concentration less than limit

(5) For the purposes of subsections (1) and (2) and section 47, if the benzene concentration in a sample is less than the method detection limit, the method detection limit is considered to be the value of the benzene concentration in the sample.

Conditions not met

46 (1) If a condition set out in paragraph 44(1)(a) or (b) is no longer met with respect to an existing high benzene tank at a facility, the operator of the facility must ensure that that tank meets the requirements of section 38 within one year after the day on which the condition was no longer met.

Reduce number of tanks

(2) If the conditions set out in paragraph 44(1)(c) are no longer met with respect to a facility, the operator of the facility must reduce by one the number of existing high benzene tanks at the facility for which an internal floating roof or external floating roof is used instead of a vapour control system, within one year after the day on which the condition was no longer met.

Reduction of two additional tanks

(3) If the conditions set out in paragraph 44(1)(c) are still not met at the end of the one-year period referred to in subsection (2), the operator must reduce by two the number of existing high benzene tanks at the facility for which an internal floating roof or external floating roof is used instead of a vapour control system each subsequent year until either

• (a) the conditions set out in paragraph 44(1)(c) are met; or
• (b) all existing high benzene tanks at the facility meet the requirements of section 38.

Reports

47 (1) An operator of a facility that, under section 44, continues to use an internal floating roof or external floating roof instead of a vapour control system at a facility to control VOC emissions, must submit reports to the Minister in accordance with subsections (2) and (4).

First report

(2) The operator must submit to the Minister, no later than 180 days after the day on which these Regulations come into force, a first report that contains data for a minimum of 6 and a maximum of 26 of the most recent consecutive sampling periods and contains the information referred to in Part 1 of Schedule 3.

Exception

(3) Despite subsection (2), if the operator established a fenceline monitoring program at the facility under the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector) before the day on which these Regulations come into force, the operator is not required to include the information referred to in items 6 to 8 of Part 1 of Schedule 3 in the first report.

Annual reports

(4) The operator must submit to the Minister, no later than 30 days after each anniversary of the day on which these Regulations come into force, an annual report that contains data for all of the sampling periods for which analytical results are available that began after the last sampling period for which data was included in the preceding report and that contains the information referred to in items 1 to 4 and 9 of Part 1 of Schedule 3 and any updates to the information referred to in items 5 to 8 of that Part.

Exception

(5) Despite subsection (4), if the operator established a fenceline monitoring program at the facility under the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector) before the day on which these Regulations come into force, the operator is not required to include updates to the information referred to in items 5 to 8 in Part 1 of Schedule 3 in the annual report.

Exceedance report

48 (1) An operator that, under section 44, continues to use an internal floating roof or external floating roof instead of a vapour control system to control VOC emissions, must notify the Minister if any benzene concentration measured under the fenceline monitoring program exceeds the applicable value set out in paragraphs 45(1)(a) to (d) or results in an arithmetic average that exceeds the applicable arithmetic average set out in paragraphs 45(2)(a) to (d), by submitting a report to the Minister that contains the information referred to in Part 2 of Schedule 3 within five days after receiving the sample analysis.

Abnormal release

(2) If, after receiving a report referred to in subsection (1) or any other information, the Minister determines that a benzene concentration or arithmetic average referred to in that subsection exceeded the applicable value or arithmetic average due to an abnormal release of benzene at the facility that is unrelated to the existing high benzene tanks at the facility, or due to an abnormal release of benzene that originated outside the facility, the Minister must notify the operator of the facility of the determination in writing and indicate which sampling periods must be excluded for the purposes of paragraph 45(3)(c).

Action Plan

Action plan

49 (1) An operator must develop and implement an action plan before

• (a) reducing the level of liquid in a high benzene tank such that its internal floating roof or external floating roof no longer floats at all times on the surface of the liquid;
• (b) cleaning the interior of a high benzene tank; or
• (c) replacing the primary seal of the internal floating roof or external floating roof of a high benzene tank.

Contents of plan

(2) The operator must submit the action plan to the Minister at least 30 days before the day on which the operator intends to implement the plan and the plan must contain the information referred to in Part 3 of Schedule 3.

Plans — conditions

(3) Within 15 days after the day on which the action plan is received, the Minister must notify the operator in writing if the Minister requires the operator to include conditions in the plan respecting

• (a) monitoring;
• (b) the repair of a defect of a high benzene tank, internal floating roof, external floating roof or primary seal and the applicable time limits;
• (c) the replacement of a primary seal and the applicable time limits;
• (d) the use of an internal floating roof, external floating roof or temporary vapour control system or any other emissions control equipment;
• (e) the implementation of other VOC emissions reduction measures;
• (f) reporting and notification;
• (g) record-keeping; and
• (h) any other matter, if the Minister considers it necessary for the purposes of these Regulations.

Revised action plan

(4) If the Minister requires the operator to include conditions in the action plan under subsection (3), the operator must not implement the action plan until the operator submits a revised action plan to the Minister including those conditions.

Implementation

(5) Despite the time limit referred to in subsection (2), the operator may implement the action plan if the Minister has notified the operator in writing that they may do so.

Update and notification

(6) The operator must notify the Minister of the completion of any activity referred to in subsection (1) within five days after the day on which the activity is completed.

Design and Use of Emissions Control Equipment

Vapour Control Systems

Loading of gasoline to trucks

50 The operator of a facility must ensure that the requirements of the National Standard of Canada CAN/CGSB-3.1000-2024, entitled Vapour Control Systems in Gasoline Distribution Networks, are met, with the exception of the record-keeping and reporting requirements, if a vapour control system is used at the facility to control VOC emissions from the loading of gasoline to trucks.

Design specifications

51 The operator of a facility must ensure that each vapour control system at the facility is installed, used and maintained in accordance with its design specifications.

Design, use and maintenance

52 In the case of a vapour recovery system or vapour destruction system, the operator must ensure that it is designed, used and maintained to

• (a) collect all vapours discharged from the tank or loading rack on which it is installed and from any vehicle tanks receiving volatile petroleum liquids from the loading rack;
• (b) capture or destroy the VOCs present in all the collected vapours in accordance with the performance requirements set out in section 57 or 58, as applicable, for the full range of inlet vapour flow rates and of VOC concentrations; and
• (c) minimize the accumulation of liquid within the vapour piping.

Free of leaks

53 (1) The operator of a facility must ensure that each vapour control system at the facility and all piping, tanks, vehicle tanks and other equipment that connect to the vapour space are free of vapour leaks and liquid leaks.

Sealed during operation

(2) The operator must ensure that all maintenance hatches and other openings to the atmosphere in piping, tanks, vehicle tanks and other equipment that connect to the vapour space are kept sealed during operation of the vapour control system, except during maintenance, inspection or repair.

Pressure-vacuum vent

(3) If the vapour control system is used to control emissions from a tank equipped with a pressure-vacuum vent, the operator must ensure that

• (a) the pressure-vacuum vent meets the requirements of section 78 and is inspected and repaired in accordance with sections 104 and 105;
• (b) if the vapour control system is a vapour recovery system or a vapour destruction system, the system and the pressure-vacuum vent are designed, used and maintained such that the pressure-vacuum vent remains sealed, except to relieve a vacuum inside the tank or to relieve pressure inside the tank during an emergency situation or a failure of the system; and
• (c) if the vapour control system is a vapour balancing system, the system and the pressure-vacuum vent are designed, used and maintained such that the pressure-vacuum vent remains sealed, except to relieve a vacuum inside the tank, to relieve pressure inside the tank in excess of the pressure relief setting set out in paragraph 78(b) or to relieve pressure inside the tank during an emergency situation or a failure of the system.

Temporary vapour control system

(4) Subsection (2) does not apply to a temporary vapour control system that has been installed on a tank under subsection 43(1) or (3).

Continuous monitoring device

54 (1) The operator of a facility must ensure that each vapour recovery system or vapour destruction system at the facility is equipped with a continuous monitoring device that is considered to be part of the vapour recovery system or vapour destruction system and that

• (a) generates an accurate measurement that indicates VOC capture or destruction, either by directly measuring VOC concentration in the exhaust gas or by measuring other relevant physical parameters, such as the temperature of the combustion chamber or exhaust, the concentration of oxygen in the exhaust or the presence of a flame;
• (b) alerts the operator if VOC capture or destruction does not meet the performance requirements set out in section 57 or 58, as applicable; and
• (c) operates at all times when the vapour recovery system or vapour destruction system is in service.

Accurate measurement

(2) A measurement generated by the continuous monitoring device is considered to be accurate if the device

• (a) measures VOC concentration with an accuracy of plus or minus 5% of a full-scale reading;
• (b) measures temperature with an accuracy of plus or minus 2°C;
• (c) measures any other relevant physical parameter with an accuracy of plus or minus 5% of a full-scale reading; or
• (d) verifies a relevant non-numeric parameter such that any inaccuracy or malfunction of the device, including an invalid reading, will trigger an alert under paragraph (1)(b).

Relevant parameters

(3) For the purposes of paragraphs (1)(a) and (2)(c) and (d), a measurement of a parameter is considered relevant to VOC capture or destruction performance if the design specifications of the vapour recovery system or vapour destruction system, including any relevant performance testing conducted during design or commissioning of the system, establish that it meets the performance requirements set out in section 57 or 58, as applicable, when the parameter is maintained in a specific state or at a specific value or within a range of specific values.

Standard operating procedures

55 The operator of a facility must, for each vapour control system at the facility, keep written standard operating procedures that

• (a) are available at the facility to all individuals who operate or maintain the vapour control system; and
• (b) contain all information required to operate and maintain the vapour control system.

Operation

56 (1) The operator of a facility must ensure that each vapour control system at the facility operates whenever vapours are displaced from the tank on which it is installed, and when the loading rack on which it is installed is used to load volatile petroleum liquids or to perform switch loading.

Exceptions

(2) Despite subsection (1),

• (a) the operation of the vapour control system may be interrupted for periods of maintenance or repair for which the total duration does not exceed 5% of the periods in a calendar year during which the tank or the loading rack is in service; and
• (b) if the vapour control system is a vapour balancing system, the operator is not required to ensure that it operates when switch loading is performed.

Performance — emissions

57 (1) The operator of a facility must ensure that each vapour recovery system or vapour destruction system at the facility does not emit more than 10 g of VOCs per m³ of vapour vented or 10 g of VOCs per standard m³ of volatile petroleum liquid loaded on a one-hour averaged basis.

Exception — benzene concentration

(2) Despite subsection (1), if the benzene concentration of the volatile petroleum liquid is equal to or exceeds 20% by weight, the operator must ensure that the vapour recovery system or vapour destruction system does not emit more than 1 g of VOCs per m³ of vapour vented or 1 g of VOCs per standard m³ of volatile petroleum liquid loaded on a one-hour averaged basis.

Performance — temporary or existing systems

58 (1) Despite subsection 57(1), the operator of a facility must ensure that each temporary vapour control system, existing vapour recovery system or existing vapour destruction system at the facility does not emit more than 35 g of VOCs per m³ of vapour vented or 35 g of VOCs per standard m³ of volatile petroleum liquid loaded on a one-hour averaged basis.

Exception — benzene concentration

(2) Despite subsection (1), if the benzene concentration of the volatile petroleum liquid is equal to or exceeds 20% by weight, the operator must ensure that the temporary vapour control system, existing vapour recovery system or existing vapour destruction system does not emit more than 5 g of VOCs per m³ of vapour vented or 5 g of VOCs per standard m³ of volatile petroleum liquid loaded on a one-hour averaged basis.

Compatible fittings

59 (1) Before a volatile petroleum liquid is loaded at a facility, the operator of the facility must ensure that the vehicle tank into or from which the liquid is loaded is equipped with interconnecting fittings that are compatible with the fittings of the vapour control system being used during loading.

Vehicle tank free of leaks

(2) Before the volatile petroleum liquid is loaded, the operator must also ensure that the vehicle tank is free of vapour leaks in accordance with the applicable standards and, if the vehicle is a truck, that the truck tank has been tested annually in accordance with the requirements set out in section 5.3.1 of the National Standard of Canada CAN/CGSB-3.1000-2024, entitled Vapour Control Systems in Gasoline Distribution Networks.

Internal Floating Roofs

Installation

60 The operator of a facility must ensure that each internal floating roof at the facility and all of its components, including seals and fittings, are installed in accordance with its design specifications.

Float on surface of liquid

61 (1) The operator must ensure that each internal floating roof floats at all times on the surface of the liquid and moves freely with changes in the liquid level.

Maximum 30 days

(2) Despite subsection (1) and subject to subsection (3), an internal floating roof may rest on a support structure or otherwise be suspended for a total duration not exceeding 30 days in a calendar year.

More than 30 days

(3) An internal floating roof may rest on a support structure or otherwise be suspended for more than 30 days in a calendar year if the diameter of the tank is 10 m or less and the tank is used after a batch or semi-batch process to temporarily hold liquid for quality control or testing purposes.

Multiple floatation compartments

62 (1) The operator must ensure that each internal floating roof with multiple floatation compartments is capable of remaining afloat on the surface of the liquid with

• (a) one pontoon or compartment punctured and flooded with liquid, if the diameter of the roof is 6 m or less;
• (b) the deck and two adjacent pontoons punctured and flooded with liquid, if the roof is a single-deck pontoon type roof and has a diameter greater than 6 m; or
• (c) two adjacent compartments punctured and flooded with liquid, if the roof is a double-deck type roof and has a diameter greater than 6 m.

Double dead weight

(2) The operator must ensure that each internal floating roof is capable of supporting at least double its dead weight, including the weight of all roof components and the force exerted by all seals during the filling of a tank.

Exposed seams

63 The operator must ensure that each seam in an internal floating roof that is exposed to vapour or liquid

• (a) is free of vapour leaks and liquid leaks; and
• (b) has an estimated life expectancy equal to the estimated life expectancy of the roof.

Continuous vapour-tight enclosure

64 (1) The operator must ensure that each internal floating roof is equipped with one or more rim seals that form a continuous vapour-tight enclosure around the entire perimeter of the floating roof, except where the rim seals are in contact with the tank wall, in which case the seal gaps must meet the requirements set out in subsection 65(2).

Rim seals — types

(2) The following rim seal configurations are permitted:

• (a) a primary seal and one or more secondary seals of any kind; and
• (b) a primary seal that is either
  • (i) a foam seal or liquid-filled seal that rests in continuous contact with the surface of the liquid, or
  • (ii) a mechanical shoe seal, measuring at least 30 cm in height, composed of a curved metal sheet designed to be in continuous contact with the tank wall for a distance extending at least 10 cm above and 10 cm below the surface of the liquid.

Gap between seal and wall of tank

65 (1) Any space that is between the rim seal of the internal floating roof and the wall of the tank and through which a uniform cylindrical probe with a diameter of 0.3 cm can pass freely is considered to be a seal gap which must be measured under the control conditions and in accordance with the procedure described in Schedule 4.

Size

(2) Subject to subsection (3), the operator must ensure that the seal gaps in each seal are less than the following dimensions:

• (a) if the seal is the primary seal,
  • (i) 4 cm wide at every point between the seal and the wall of the tank, and
  • (ii) a cumulative total of 200 cm² per metre of the tank’s diameter; and
• (b) if the seal is a secondary seal,
  • (i) 1.3 cm wide at every point between the seal and the wall of the tank, and
  • (ii) a cumulative total of 20 cm² per metre of the tank’s diameter.

More than one secondary seal

(3) If the internal floating roof is equipped with more than one secondary seal, the operator must ensure that at least one of the secondary seals meets the size requirements set out in subparagraphs (2)(b)(i) and (ii).

Openings

66 (1) Subject to subsections (2) and (3), the operator must ensure that each opening in the deck of an internal floating roof is sealed at all times such that they are free of vapour leaks and liquid leaks.

Opening — moving component

(2) The operator must ensure that each opening in the deck of the internal floating roof that allows a component of the tank to move relative to the floating roof when the liquid level in the tank changes is equipped with

• (a) a flexible sleeve that encloses the component; or
• (b) a gasket that is in contact with the entire perimeter of the component and, if there is an internal space in the component that allows for the passage of vapour, an internal float.

Exceptions

(3) The operator may unseal an opening when necessary to prevent excess pressure or vacuum in the tank during exceptional circumstances outside of the tank’s normal operating conditions or when necessary for tank maintenance, inspection or repair.

Rims

67 The operator must ensure that each internal floating roof is equipped, around its periphery and around all of its openings, with rims that are free of vapour leaks and liquid leaks and that extend

• (a) at least 15 cm above the liquid, except for the rims around drains; and
• (b) at least 10 cm below the liquid, except for the rims around vents or vacuum breakers.

Materials

68 The operator must ensure that each component of an internal floating roof is made of materials that

• (a) are impermeable to vapours;
• (b) are chemically compatible with the liquid in the operating environment such that they do not suffer damage that reduces the emissions control efficacy of the component during its estimated life expectancy; and
• (c) are physically compatible with weather conditions at the facility such that they do not suffer damage that reduces the emissions control efficacy of the component during its estimated life expectancy.

External Floating Roofs

Installation

69 The operator of a facility must ensure that each external floating roof at the facility and all of its components, including seals and fittings, are installed in accordance with its design specifications.

Float on surface of the liquid

70 (1) The operator must ensure that each external floating roof floats at all times on the surface of the liquid and moves freely with changes in the liquid level.

Maximum 30 days

(2) Despite subsection (1), an external floating roof may rest on a support structure or otherwise be suspended for a total duration not exceeding 30 days in a calendar year.

Multiple floatation compartments

71 (1) The operator must ensure that each external floating roof is a single-deck pontoon type roof or double-deck type roof that is capable of remaining afloat on the surface of the liquid with

• (a) one pontoon or compartment punctured and flooded with liquid, if the diameter of the roof is 6 m or less;
• (b) the deck and two adjacent pontoons punctured and flooded with liquid, if the roof is a single-deck pontoon type roof and has a diameter greater than 6 m; or
• (c) two adjacent compartments punctured and flooded with liquid, if the roof is a double-deck type roof and has a diameter greater than 6 m.

Rain

(2) The operator must ensure that each external floating roof is capable of remaining afloat on the surface of the liquid after receiving 25 cm of rain over the surface of its deck in a 24-hour period with the primary drains disabled, unless the external floating roof is a double-deck type roof equipped with functional emergency drains that are designed to reduce the accumulation of water on the roof to a volume that the roof may safely support.

Ice or snow

(3) The operator must ensure that each external floating roof is designed and maintained to remain afloat on the surface of the liquid under an accumulation of ice or snow that is reasonably expected at the geographic location of the facility.

Exposed seams

72 The operator must ensure that each seam in an external floating roof that is exposed to vapour or liquid

• (a) is free of vapour leaks and liquid leaks; and
• (b) has an estimated life expectancy equal to the estimated life expectancy of the roof.

Continuous vapour-tight enclosure

73 (1) The operator must ensure that each external floating roof is equipped with a primary seal and a secondary seal that form a continuous vapour-tight enclosure around the entire perimeter of the floating roof, except where the seals are in contact with the tank wall, in which case the seal gaps must meet the requirements set out in subsection 74(2).

Primary seal — types

(2) The operator must ensure that each primary seal is of one of the following types:

• (a) a foam seal or liquid-filled seal that rests in continuous contact with the surface of the liquid; or
• (b) a mechanical shoe seal composed of a curved metal sheet designed to be in continuous contact with the tank wall for a distance extending at least 60 cm above and 10 cm below the surface of the liquid.

Secondary seal — type

(3) The operator must ensure that each secondary seal is of a type that is mounted on the rim of the external floating roof.

Peripheral structure

(4) A peripheral structure that covers a primary or secondary seal for the primary purpose of providing it shelter from rain, snow or ultraviolet radiation is not considered to be a secondary seal.

Gap between seal and wall of tank

74 (1) Any space that is between the rim seal of the external floating roof and the wall of the tank is considered to be a seal gap, which must be measured under the control conditions and in accordance with the procedure described in Schedule 4.

Size

(2) Subject to subsection (3), the operator must ensure that the seal gaps in each seal are less than the following dimensions:

• (a) if the seal is the primary seal,
  • (i) 4 cm wide at every point between the seal and the wall of the tank, and
  • (ii) a cumulative total of 200 cm² per metre of the tank’s diameter; and
• (b) if the seal is a secondary seal,
  • (i) 1.3 cm wide at every point between the seal and the wall of the tank, and
  • (ii) a cumulative total of 20 cm² per metre of the tank’s diameter.

More than one secondary seal

(3) If the external floating roof is equipped with more than one secondary seal, the operator must ensure that at least one of the secondary seals meets the size requirements set out in subparagraphs (2)(b)(i) and (ii).

Openings

75 (1) Subject to subsections (2) to (4), the operator must ensure that each opening in the deck of an external floating roof is sealed at all times such that it is free of vapour leaks and liquid leaks.

Emergency drain

(2) The operator must ensure that each opening in the deck of the external floating roof that is an emergency drain is equipped with a cover that encloses at least 90% of the area of the opening.

Opening — passage of moving component

(3) The operator must ensure that each opening in the deck of the external floating roof that allows a component of the tank to move relative to the floating roof when the liquid level in the tank changes is equipped with

• (a) a flexible sleeve that encloses the component; or
• (b) a gasket that is in contact with the entire perimeter of the component and, if there is an internal space in the component that allows for the passage of vapour, an internal float.

Exceptions

(4) The operator may unseal an opening when necessary to prevent excess pressure or vacuum in the tank during exceptional circumstances outside of the tank’s normal operating conditions or when necessary for tank maintenance, inspection or repair.

Rims

76 The operator must ensure that each external floating roof is equipped, around its periphery and around all of its openings, with rims that are free of vapour leaks and liquid leaks and that extend at least 10 cm below the liquid, except for the rims around vents or vacuum breakers.

Materials

77 The operator must ensure that each component of an external floating roof is made of materials that

• (a) are impermeable to vapours;
• (b) are chemically compatible with the liquid in the operating environment such that they do not suffer damage that reduces the emissions control efficacy of the component during its estimated life expectancy; and
• (c) are physically compatible with weather conditions expected at the facility such that they do not suffer damage that reduces the emissions control efficacy of the component during its estimated life expectancy.

Pressure-Vacuum Vents

Requirements

78 The operator of a facility must ensure that each pressure-vacuum vent at the facility meets the following requirements:

• (a) it must close and form a seal that is free from vapour leaks and liquid leaks when there is no pressure differential between the inside of the tank and the atmosphere;
• (b) its pressure and vacuum relief settings must be set to the maximum pressure and vacuum that is allowable within the limits of the tank design pressure; and
• (c) it must be installed, operated and calibrated in accordance with its design specifications.

Ventilation

79 The operator must ensure that the tank opens to the atmosphere only through the pressure-vacuum vent, except during sampling or tank maintenance, inspection or repair.

Alternative Emissions Control Equipment

Application for permit

80 (1) The operator of a facility may apply to the Minister for a permit to use alternative emissions control equipment on tanks or loading racks at the facility rather than the emissions control equipment required under any of sections 38 to 40 and 42.

Prohibited substitutions

(2) However, the operator may not apply for a permit to use

• (a) an internal floating roof or external floating roof in place of a vapour control system; or
• (b) a pressure-vacuum vent in place of an internal floating roof, external floating roof or vapour control system.

Contents of application

(3) The permit application must contain the information referred to in Schedule 5 and may be submitted for more than one of the operator’s facilities.

Clarifications or additional information

(4) The Minister may, on receiving the permit application, require that the applicant provide any clarifications or additional information if they are necessary for the application to be considered.

Issuance

81 (1) The Minister may issue a permit referred to in subsection 80(1) if the Minister has determined that the information provided in the application demonstrates that the alternative emissions control equipment is, in all situations in which it would be used, at least as effective at controlling VOC emissions as the emissions control equipment that it would replace.

Permit – information

(2) The issued permit must set out the following information:

• (a) the period of validity of the permit;
• (b) the names of the facilities to which the permit relates;
• (c) the identifiers of the tanks and loading racks that may be equipped with the alternative emissions control equipment;
• (d) the situations in which the alternative emissions control equipment may be used; and
• (e) the conditions to be met while using the alternative emissions control equipment.

Permit – conditions

(3) For the purposes of paragraph (2)(e), the Minister may set out conditions in the permit respecting:

• (a) the design and operation of the alternative emissions control equipment;
• (b) monitoring and any applicable limits on monitored parameters;
• (c) procedures and practices for the maintenance, inspection and repair of the alternative emissions control equipment;
• (d) reporting and notification;
• (e) record-keeping;
• (f) procedures for updating administrative information; and
• (g) any other matter, if the Minister considers it necessary for the purposes of these Regulations.

Permit — refusal

82 (1) If the information required under subsections 80(3) and (4) has not been provided or is insufficient to enable the Minister to consider the application, the Minister must refuse to issue the permit, notify the applicant in writing of the reasons for the refusal and provide the applicant an opportunity to make written representations.

30 days

(2) The written representations, if any, must be submitted to the Minister within 30 days after the day on which the applicant receives the Minister’s notice of refusal.

Decision of the Minister

(3) After providing the applicant an opportunity to make written representations, the Minister must take one of the following measures:

• (a) notify the applicant in writing of the decision to issue the permit and issue the permit in accordance with section 81; or
• (b) notify the applicant in writing of the decision to refuse to issue the permit.

Renewal of permit

83 (1) A permit holder who wishes to renew their permit must submit an application for renewal to the Minister at least 60 days before the day on which the permit expires.

Contents of application for renewal

(2) The application for renewal must contain an update of the information provided under subsection 80(3).

Clarifications or additional information

(3) The Minister may, on receiving an application for renewal, require that the applicant provide any clarifications or additional information that is necessary for the Minister to consider the application.

Renewal

(4) The Minister may renew the permit if the Minister determines that the information provided in the application for renewal demonstrates that the alternative emissions control equipment is, in all situations in which it would be used, at least as effective at controlling VOC emissions as the emissions control equipment that it would replace.

Conditions

(5) The Minister may modify any of the conditions set out in the initial permit under subsection 81(3) and if the Minister does so, the Minister must set out those modified conditions in the renewed permit.

Notice to Minister

84 If a permit holder receives information demonstrating that the alternative emissions control equipment does not control VOC emissions as effectively as the equipment that it replaced, or monitoring data establishing that the limits referred to in paragraph 81(3)(b) are no longer met, the permit holder must notify the Minister within 30 days after the day on which they received that information or data.

Modification of permit

85 (1) The Minister may modify a permit issued under subsection 81(1) if the Minister has reasonable grounds to believe that the alternative emissions control equipment does not control VOC emissions as effectively as the emissions control equipment that it replaced.

Revocation of permit

(2) The Minister may revoke a permit issued under subsection 81(1) if the Minister has reasonable grounds to believe that

• (a) the alternative emissions control equipment does not control VOC emissions as effectively as the emissions control equipment that it replaced;
• (b) the conditions set out in the permit have not been met; or
• (c) the permit holder has provided false or misleading information in support of their application.

Notice of modification or revocation

(3) Before modifying or revoking a permit, the Minister must notify the permit holder in writing of the reasons for the modification or revocation and provide the permit holder an opportunity to make written representations concerning the modification or revocation.

30 days

(4) For the purposes of subsection (3), the permit holder may submit written representations to the Minister no later than 30 days after the day on which they receive the notice of modification or revocation.

Decision of the Minister

(5) If, after providing the permit holder an opportunity to make written representations, the Minister decides to modify or revoke the permit, the Minister must

• (a) notify the permit holder of the modification or revocation; and
• (b) if applicable, notify the permit holder of the date on which the permit holder must cease to use the alternative emissions control equipment and the date on which the permit holder must begin to use the emissions control equipment required under any of sections 38 to 40 and 42.

Inspection, Testing and Repair

Vapour Control Systems

Inspections and Tests

Monthly inspection

86 (1) The operator of a facility must, at least once a month and no less than 14 days after the day on which the previous inspection was performed, visually inspect all components of each vapour control system at the facility for vapour leaks and liquid leaks or any other defects that can be detected visually.

Annual inspection

(2) The operator must, at least once in a calendar year and no less than 10 months after the day on which the previous inspection was performed, inspect each vapour control system for vapour leaks with one of the leak detection instruments referred to in subsection 26(1).

Excluded components

(3) Any component of the vapour control system that is normally operated at an internal pressure that is at least 5 kPa below ambient pressure is not required to be inspected under subsection (2).

Performance test — defects

87 (1) The operator of a facility must test the performance of each vapour control system for the defects referred to in subsection 90(3) within the time limits set out in the design specifications and at least once every five years.

Design specifications

(2) Despite subsection (1), if the vapour control system is a vapour destruction system designed with the primary purpose of producing useful heat or energy, or if it is a flare, the operator is required to perform only the tests indicated in the system’s design specifications.

Performance test — modifications

88 (1) If the vapour control system is a vapour recovery system or vapour destruction system, the operator must ensure that the performance test referred to in section 87 is performed in accordance with section 7 of the National Standard of Canada CAN/CGSB 3.1000–2024, entitled Vapour Control Systems in Gasoline Distribution Networks, with the following modifications:

• (a) the test method applies to all vapour recovery systems and vapour destruction systems;
• (b) a reference to “terminal” is to be read as a reference to “facility”;
• (c) a reference to “gasoline” is to be read as a reference to “volatile petroleum liquid”;
• (d) a reference to “gasoline vapour” is to be read as a reference to “ vapour”;
• (e) if the vapour control system is used to control VOC emissions from a tank, the performance test period must be of the same duration as the performance test period set out in the standard and include at least one hour during which the tank is being filled at the maximum rate;
• (f) the use of alternate test methods, including continuous emissions monitoring, is not permitted;
• (g) the total hydrocarbon analyzer must be a separate device from the continuous monitoring device and both devices must independently collect data throughout the test period;
• (h) detections of methane and ethane may be excluded from the results collected by the total hydrocarbon analyzer by either
  • (i) using a device of a type that is insensitive to those substances, or
  • (ii) subtracting the effect of those substances from the reading using a calibration or correction factor that is established on the day of the test and appropriate for the testing conditions, including temperature, pressure, overall atmospheric composition and actual vapour composition;
• (i) in all calculations and calibrations, references to propane or the properties of propane, including density or molecular mass, must be replaced by references to another appropriate substance or to the properties of that other substance whenever necessary to accurately represent the properties of a volatile petroleum liquid;
• (j) the volume of substances that are not volatile petroleum liquids must not be included in calculations relating to the volume of liquid loaded; and
• (k) the results of the calculations may indicate the performance of the vapour control system in terms of the mass of VOCs emitted per m³ of vapour vented instead of the mass of VOCs emitted per litre of liquid loaded.

More than one tank

(2) For the purposes of paragraph (1)(e), if the vapour control system is used to control the emissions of multiple tanks, only one tank must be filled during the test.

Continuous monitoring device

(3) The accuracy of a continuous monitoring device referred to in paragraph 54(1)(a) is evaluated by comparing the measurements generated by the device during the test to the results of the performance test referred to in section 87.

Vapour balancing system — test

89 (1) If the vapour control system is a vapour balancing system, the operator must ensure that the performance test referred to in section 87 covers the entire duration of the loading from a tank to a vehicle tank and the entire duration of the loading from a vehicle tank to a tank.

Test elements

(2) The test must include the following elements:

• (a) the use of a calibrated pressure gauge to monitor the pressure at the vapour outlet of the vehicle tank during loading; and
• (b) the use of visual, auditory or olfactory methods to monitor the pressure-vacuum vents on the vehicle tank and the tank to determine whether any of the vents open during loading.

Loading during the test

(3) During the test, loading must be performed in accordance with the operator’s standard operating procedures, involve vehicles typically used at the facility and be performed without modifications to enhance system performance for the purpose of the test.

Repair

Repair — deadline

90 (1) The operator of a facility must, within 45 days after the day on which a defect of any vapour control system at the facility is detected

• (a) repair the defect and perform any tests or inspections necessary to confirm that the repair is successful; or
• (b) use a temporary vapour control system.

Repair deadline exception

(2) Despite subsection (1), if the operation of the vapour control system is not required on the last day of the period referred to in subsection (1), the operator must ensure that the measures referred to in paragraph 1(a) or (b) are taken before the operation of the vapour control system is next required.

Defects

(3) A vapour control system has a defect if

• (a) it has a vapour leak or liquid leak;
• (b) in the case of a vapour recovery system or vapour destruction system,
  • (i) it is equipped with a continuous monitoring device that does not meet the requirements of section 54, or
  • (ii) its VOC recovery or destruction performance is insufficient to allow it to meet the requirements of section 57 or 58, as the case may be;
• (c) in the case of a vapour balancing system,
  • (i) it has a measured pressure in excess of 4.5 kPa at the vehicle tank vapour outlet, or
  • (ii) its pressure-vacuum vents are open at a pressure lower than the pressure relief setting set out in paragraph 78(b) during loading activities; or
• (d) it has any other defect that is likely to reduce its performance.

Internal Floating Roofs and External Floating Roofs

Inspection of Internal Floating Roof

Monthly inspection

91 (1) The operator of a facility must ensure that the space above each internal floating roof at the facility is inspected at least once a month and no less than 14 days after the day on which the previous inspection was performed.

Inspections omitted

(2) Despite subsection (1), the operator may omit up to four inspections in one calendar year if weather conditions or unforeseen circumstances cause safety concerns or access problems that render inspection impracticable.

LEL%

(3) An inspection must include a determination of the value of the LEL% in the space above the internal floating roof under the control conditions and in accordance with the procedure described in Schedule 6.

Baseline LEL%

92 (1) The operator must calculate a baseline LEL% for the purposes of evaluating the performance of the internal floating roof.

Calculation

(2) Subject to subsection (3), the baseline LEL% is the arithmetic average of all the values of the LEL% determined in the space above the internal floating roof over the previous four years.

Excluded

(3) The following values are excluded from the calculation of the baseline LEL%:

• (a) all values of the LEL% determined before any total replacement of the primary seal or secondary seal;
• (b) all values of the LEL% that exceed 20 or, if the benzene concentration of the volatile petroleum liquid in the tank is greater than or equal to 20% by weight, that exceed 10; and
• (c) all values of the LEL% determined before the day on which these Regulations come into force.

No established baseline LEL%

(4) Despite subsection (1), there is no established baseline LEL% if there are less than 12 LEL% values included in the calculation.

Established baseline LEL%

(5) If there is an established baseline LEL%, the value of the LEL% in the space above the internal floating roof must not exceed the following thresholds:

• (a) 150% of the baseline LEL%, if the baseline LEL% is greater than or equal to 5; and
• (b) 7.5, if the baseline LEL% is less than 5.

No established baseline LEL%

(6) If there is no established baseline LEL%, the value of the LEL% in the space above the internal floating roof must not exceed the following thresholds:

• (a) 10, if the tank is a high benzene tank;
• (b) 90, if the tank is an inerted tank that is not a high benzene tank; and
• (c) 20, in all other cases.

Excess LEL% — second inspection

(7) If, during a first inspection, the value of the LEL% exceeds the thresholds set out in subsection (5) or (6) but does not exceed the thresholds set out in paragraphs 101(1)(b) or (c), a second inspection may be performed within seven days after the day of the first inspection and if, during the second inspection, the value of the LEL% does not exceed the applicable thresholds set out in subsection (5) or (6), the value determined during the first inspection is not a defect, despite paragraph 100(5)(d).

Inspection every 20 years

93 (1) The operator of a facility must ensure that each internal floating roof at the facility and the interior of the tank in which it is installed are inspected every 20 years and that the inspection includes

• (a) a measurement of the seal gap under the control conditions and in accordance with the procedure described in Schedule 4, unless the rim seal is being replaced at the time of the inspection;
• (b) an inspection of all hatches, covers and other emissions control devices, including seals and internal floats, to locate tears, holes, corrosion, swelling, embrittlement or any other damage that would reduce their emissions control efficacy;
• (c) if applicable, a test operation of the hatches to verify that they seal automatically after use;
• (d) if the tank is not in service at the time of inspection, the servicing, testing or replacement of vents and vacuum breakers to ensure that they are in good working order and that they will remain closed when the floating roof is floating on the liquid;
• (e) an inspection of the floating roof and all other emissions control equipment for structural defects and corrosion;
• (f) an inspection of the seams in the internal floating roof for potential vapour leaks or liquid leaks, openings or damage;
• (g) if the tank is not in service at the time of inspection, an inspection of the inside of the pontoons and a determination of the value of the LEL% inside the pontoons to detect vapour leaks and liquid leaks;
• (h) if applicable, an inspection of the bolting bar on the rim-mounted secondary seals for corrosion and broken welds;
• (i) if applicable, a test operation of the liquid level alarms and automatic gauging systems;
• (j) if applicable, a visual inspection of the inside of the guide pole for protrusions that are likely to damage the vapour control float;
• (k) if applicable, an inspection of the vapour control float or cover inside the guide pole; and
• (l) an inspection of the exposed part of the internal wall of the tank for grooving, corrosion, coating failures and out-of-roundness.

Start of period

(2) The 20-year period referred to in subsection (1) is considered to have begun on the later of the following days:

• (a) the day on which the tank was first in service, but only if the operator’s records demonstrate that all tests or inspections verifying the correct installation and function of the tank and the internal floating roof that are required by design specifications have been performed; and
• (b) the day on which the most recent internal inspection of the tank was performed, but only if the operator’s inspection report demonstrates that the inspection was completed by a person who holds a valid API 653 - Aboveground Storage Tank Inspector certificate issued by the American Petroleum Institute.

No applicable days

(3) If neither of the days referred to in paragraphs (2)(a) and (b) applies or if the applicable day has occurred more than ten years before the day on which these Regulations come into force, the operator must ensure that the first inspection required under subsection (1) is performed no later than ten years after the day on which these Regulations come into force.

Inspection of External Floating Roof

Monthly inspection

94 (1) The operator of a facility must ensure that the upper surface of each external floating roof at the facility is visually inspected at least once a month and no less than 14 days after the day on which the previous inspection was performed, for the defects referred to in paragraphs 100(5)(e) to (g).

Inspection without delay

(2) Despite subsection (1), if weather conditions or unforeseen circumstances cause safety concerns or access problems that render an inspection impracticable, the operator may delay the inspection but must perform it without delay once the circumstances permit and must not delay it by more than seven days.

Annual inspection

95 (1) The operator of a facility must ensure that the upper surface of each external floating roof at the facility is visually inspected annually – no less than 10 months after the day on which the previous inspection was performed – for the defects referred to in paragraphs 100(5)(a), (c) and (e) to (h) and must ensure that the secondary seal gaps are measured annually under the control conditions and in accordance with the procedure described in Schedule 4.

No more than two metres

(2) The inspection of an opening of the external floating roof deck, as part of the visual inspection referred to in subsection (1), must be performed from a distance of no more than two metres from the opening.

Inspection every five years

96 The operator of a facility must ensure that each external floating roof at the facility and the exposed part of the internal wall of the tank in which it is installed are inspected every five years and that the inspection includes

• (a) a measurement of the primary seal gaps under the control conditions and in accordance with the procedure described in Schedule 4, unless the rim seal is being replaced at the time of the inspection;
• (b) an inspection of the primary and secondary seals in which they are pulled back all around the internal wall and checked for their proper operation;
• (c) an inspection of the secondary seals for signs of buckling or indications that the angle with the internal wall is too shallow;
• (d) an inspection of all hatches, covers and other emissions control devices, including seals and internal floats, to locate tears, holes, corrosion, swelling, embrittlement or any other damage that would substantially reduce their emissions control efficacy;
• (e) an inspection of the exposed part of internal wall of the tank for grooving, corrosion, coating failures and out-of-roundness;
• (f) if applicable, an inspection of the automatic gauging guide of the tank and the lower sheave housing for signs of vapour leaks and liquid leaks;
• (g) an inspection of the wind girder for corrosion damage;
• (h) a visual inspection of the external floating roof for inadequate drainage;
• (i) if applicable, a test operation of the hatches to verify that they seal automatically after use;
• (j) if applicable, an inspection of all guide poles and gauge wells for thinning and signs of grooving or wear;
• (k) an inspection of the levelness of the external floating roof, at a minimum of three locations, in which the distance from the roof rim to a horizontal weld seam that is above the floating roof is measured;
• (l) an inspection of the emergency drains to ensure that the covers or sealing are adequate;
• (m) if applicable, an inspection of the inside the pontoons and a determination of the value of the LEL% inside of the pontoons to detect vapour leaks and liquid leaks;
• (n) an inspection of the upper deck of the external floating roof for paint failure and corrosion; and
• (o) if applicable, an inspection of the bolting bar on the rim-mounted secondary seals for corrosion and broken welds.

Measurement of seal gap

97 Within 60 days after the day on which a rim seal of an external floating roof is replaced, the operator must measure the seal gaps under the control conditions and in accordance with the procedure described in Schedule 4.

Inspector certificate

98 The operator must ensure that all inspections referred to in subsection 93(1) and section 96 are performed by a person who holds a valid API 653 - Aboveground Storage Tank Inspector certificate issued by the American Petroleum Institute.

Other Requirements

Reduced inspection intervals

99 If design specifications or inspection findings indicate that the estimated life expectancy of any component of an internal floating roof or external floating roof is shorter than the inspection interval specified in subsection 93(1) or section 96, as the case may be, the interval between inspections in respect of the component must be reduced to match its estimated life expectancy.

Repair

Repair — tank in service

100 (1) Subject to subsections (2), (3) and 101(1) to (4), if a defect referred to in subsection (5) is detected when a tank is in service at a facility, the operator of the facility must take one of the following measures:

• (a) in the case of a defect of a tank, internal floating roof or external floating roof, the operator must, within 60 days after the day on which the defect is detected,
  • (i) remove the tank from service, or
  • (ii) repair the defect and perform any tests or inspections necessary to confirm that the repair is successful; or
• (b) in the case of a defect of an internal floating roof or the tank in which it is installed, the operator must equip the tank with a temporary vapour control system within 15 days after the day on which the defect is detected and repair the defect and perform any tests or inspections necessary to confirm that the repair is successful within 180 days after that day.

Tank designated under subsection 125(1)

(2) Subject to section 101(1), if a defect of a tank designated as a deferred application tank under subsection 125(1) can be repaired only when the tank is not in service, the repair may be delayed until the tank is removed from service.

Defect to rim seal

(3) In the case of a defect of a rim seal, the time limit for taking the measures referred to in subparagraph (1)(a)(ii) is extended to 90 days after the day on which the defect is detected if

• (a) the cumulative total surface area of all seal gaps is less than 1000 cm² per m of the tank’s diameter; and
• (b) within 30 days after the day on which the defect is detected, a person who holds a valid API 653 - Aboveground Storage Tank Inspector certificate issued by the American Petroleum Institute determines that the tank is free of any other detected defects that would prevent the repair of the rim seal while the tank is in service.

Repair cannot be completed

(4) If, after attempting a repair of a rim seal for the purposes of subsection (3), the operator determines that the defect of the rim seal cannot be repaired while the tank is in service, the operator must remove the tank from service within 45 days after the day on which the determination is made.

Defects

(5) An internal floating roof or external floating roof has a defect if

• (a) the tank in which it is installed does not meet the requirements of section 37 such that the efficacy of the internal floating roof or external floating roof in controlling emissions could be reduced;
• (b) it has a seal gap that exceeds the size requirements set out in subsections 65(2) and (3) and 74(2) and (3);
• (c) its deck has an opening that does not meet the requirements of sections 66 and 75;
• (d) in the case of an internal floating roof, the value of the LEL% in the space above it exceeds the applicable threshold set out in subsection 92(5) or (6);
• (e) in the case of an external floating roof, it has inadequate drainage or an accumulation of snow, ice or debris that compromises its capacity to remain afloat on the surface of the liquid;
• (f) volatile petroleum liquids are observed to be present on its upper surface more than once in a 12-month period or present over an area of more than 1 m²;
• (g) it or the tank in which it is installed has a structural defect or obstruction that could impair the movement of the internal floating roof or the external floating roof; or
• (h) it or the tank in which it is installed has any other defect that could reduce the efficacy of the internal floating roof or external floating roof in controlling emissions.

Major defects

101 (1) An operator must take the measures described in subsections (2) and (5) when any of the following defects are detected:

• (a) an internal floating roof or external floating roof has sunk;
• (b) the value of the LEL% in the space above an internal floating roof in a high benzene tank exceeds 20; or
• (c) the value of the LEL% in the space above an internal floating roof in a tank, other than an inerted tank, exceeds 50.

Measures

(2) Subject to subsections (3) and (4), if a defect referred to in subsection (1) is detected, the operator must, as soon as the circumstances permit, cease to load volatile petroleum liquids into the tank and either

• (a) empty the tank of all volatile petroleum liquid; or
• (b) use a temporary vapour control system to control emissions from the tank.

Choice of measure

(3) If the measures referred to in paragraphs (2)(a) and (b) can both be performed safely, the operator of a facility must choose the measure that can be completed the soonest.

Additional measures

(4) If the operator takes the measure referred to in paragraph (2)(b), the operator must, as soon as the circumstances permit, either repair the defect and perform any tests or inspections necessary to confirm that the repair is successful or empty the tank of all volatile petroleum liquid.

Report

(5) For the purposes of subsection (1), the operator must

• (a) as soon as feasible after the defect is detected, submit a report to the Minister that contains the information referred to in Schedule 7;
• (b) notify the Minister as soon as feasible of any change to the planned measures or expected timelines described in the report; and
• (c) update the report and submit the update to the Minister within five days after the day on which the defect is repaired.

Defects — existing tanks

102 For the purposes of subsection 100(1), all defects detected during an inspection of an existing tank performed before the day on which these Regulations come into force are considered to have been detected one year after the day on which these Regulations come into force.

VOC Emissions Minimization Plan

Plan

103 (1) Before removing a tank – other than a high benzene tank – from service or replacing the primary seal of the internal floating roof or external floating roof of such a tank while it is in service, an operator must develop a VOC emissions minimization plan that includes the information referred to in Schedule 8 and must implement that plan during the removal or replacement.

Measures — removal from service

(2) In the case of the removal of a tank from service, the VOC emissions minimization plan must include at least one of the following measures:

• (a) substitution, dilution or chemical decontamination of the liquid in the tank such that the liquid is no longer considered to be a volatile petroleum liquid;
• (b) completion of the removal within 15 days after the tank’s internal floating roof or external floating roof is no longer floating on the surface of the liquid; or
• (c) use of a temporary vapour control system under section 43.

Record

(3) The operator must record any deviations to the measures included in the plan and the date of completion of the plan.

Pressure-Vacuum Vent

Inspection

Pressure-vacuum vent

104 (1) The operator of a facility must ensure that each pressure-vacuum vent at the facility is inspected annually and no less than 10 months after the day on which the previous inspection was performed to ensure that it meets the requirements set out in paragraph 78(a).

Five years

(2) The operator must ensure that the pressure-vacuum vent is inspected every five years to ensure it meets the requirements set out in paragraphs 78(b) and (c).

Repair

Defect detected

105 (1) If a defect of a pressure-vacuum vent is detected while the tank on which it is installed is in service, the operator must ensure that the defect is repaired as soon as feasible and no later than 45 days after the day on which it was detected.

Defects

(2) A pressure-vacuum vent for which the requirements set out in section 78 have not been met is considered to have a defect.

Extended Repair Plan

Reasons

106 (1) The operator of a facility must develop an extended repair plan for a defect of a tank or its internal floating roof or external floating roof if an authorized official determines that the tank needs to be removed from service so that the defect may be repaired but the tank cannot, for one of the following reasons, be removed from service such that the repair can be completed within the applicable time limit set out in section 100:

• (a) the tank’s removal from service would require a shutdown of some or all of the petroleum processing equipment at the facility;
• (b) there are no options at the facility or elsewhere for the storage, processing, treatment or disposal of the contents of the tank; or
• (c) there are significant risks to safety, human health or the environment associated with the tank’s removal from service that would be mitigated with additional repair time.

Submission to Minister and content of plan

(2) The extended repair plan must be submitted to the Minister at least 30 days before the applicable time limit set out in section 100 ends and must include the information referred to in Schedule 9.

Clarifications or additional information

(3) The Minister may, on receiving the extended repair plan, require that the operator provide any clarifications or additional information.

Re-submission of plan

(4) If, on receiving the extended repair plan, the Minister has reasonable grounds to believe that the date set out in the plan for the tank’s removal from service is later than warranted by the circumstances, the Minister may require that the operator resubmit the plan and change that date to a date specified by the Minister.

Implementation

(5) The operator must implement the extended repair plan beginning the day after the day on which the applicable time limit set out in section 100 ends and must remove the tank from service within the time limit set out in the extended repair plan.

Reason referred to in paragraph (1)(b) or (c)

(6) If an operator implements an extended repair plan for a reason referred to in paragraph (1)(b) or (c), the operator must cease filling the tank with any volatile petroleum liquids beginning on the day after the day on which the applicable time limit set out in section 100 ends.

Update and notification

(7) An operator that implements an extended repair plan must

• (a) if there is a change to the information referred to in items 9 to 11 of Schedule 9, update and resubmit the extended repair plan to the Minister as soon as feasible before the change takes effect; and
• (b) notify the Minister of the day on which the tank is removed from service within five days after that day.

Approvals

Federal, provincial or municipal approval

107 (1) If the measures that an operator has to take to repair a defect require approval from a federal, provincial or municipal authority, the following periods are not included in the calculation of the time limits set out in subsections 90(1) and 100(1), (3) and (4), subsection 105(1) and section 106, as applicable:

• (a) a single period beginning on the day on which the defect is detected and ending 14 days after that day, so that the approval may be requested from the federal, provincial or municipal authority; and
• (b) any period during which the federal, provincial or municipal authority’s approval is pending.

Request as soon as feasible

(2) The operator must request the approval of the federal, provincial or municipal authority as soon as the circumstances permit.

Inventory

Inventory

108 The operator of a facility must establish and maintain an inventory in respect of the facility that contains the information referred to in Schedule 10.

Record-Keeping

Records

Emissions control equipment

109 The operator of a facility must maintain, in respect of each piece of emissions control equipment at the facility, a record that contains the following information and any supporting documents:

• (a) the identifier of the emissions control equipment;
• (b) the type of emissions control equipment and the identifier of the tank or loading rack on which it was installed;
• (c) the year of installation of the emissions control equipment on the tank or loading rack;
• (d) the design specifications of the emissions control equipment;
• (e) if the emissions control equipment is a vapour control system
  • (i) the dates and the duration of the periods during which the vapour control system is in service and not in service,
  • (ii) for each period during which the vapour control system is not in service, the reasons why it is not in service and an indication of whether the tank or loading rack on which it is installed is in service during that period,
  • (iii) the total duration of the periods in a calendar year during which the operation of the vapour control system is interrupted for maintenance or repair under paragraph 56(2)(a),
  • (iv) the standard operating procedures kept under section 55,
  • (v) a maintenance plan for the vapour control system that includes
    • (A) the dates on which it is expected to be removed from service or returned to service and the reasons for the removal or return,
    • (B) the latest allowable dates of the next inspections under subsections 86(1) and (2), and
    • (C) the latest allowable date of the next performance test under section 87,
  • (vi) information on the performance tests of the vapour control system required under section 87, including
    • (A) the date of each test performed,
    • (B) if a test was omitted or was not performed within the required time limit, the reason why,
    • (C) for each test performed, the relevant parameters referred to in subsection 54(3) used to establish the vapour control system’s performance, if applicable,
    • (D) the test method followed for each test,
    • (E) the instruments used to perform each test,
    • (F) the calibration test method for the instruments used to perform each test, the dates of the calibration tests and the results of the calibration tests,
    • (G) the operating conditions under which each test was performed,
    • (H) the results of each test and all data collected during each test,
    • (I) any discrepancies identified between the results of any test and the performance indicated by the continuous monitoring device, if applicable, and
    • (J) the name of the person who performed each test and the name of their employer;
• (f) if the emissions control equipment is a vapour recovery system or vapour destruction system,
  • (i) any monitoring data generated by its continuous monitoring device in accordance with paragraph 54(1)(a) during the previous 12 months, and
  • (ii) any information on the accuracy and relevance, as determined in accordance with subsections 54(2) and (3), of the measurements generated by its continuous monitoring device during the previous 12 months;
• (g) if the emissions control equipment is a pressure-vacuum vent, any data in respect of its calibration under paragraph 78(c);
• (h) information demonstrating that the requirements set out in section 59 have been met, if applicable;
• (i) if the emissions control equipment is a vapour control system, information on the inspections required under section 86, including
  • (i) the date of each inspection performed,
  • (ii) if an inspection was omitted or was not performed within the required time limits, the reason why,
  • (iii) an indication of whether each inspection was performed visually or using a leak detection instrument and, in the latter case, the type of instrument used and its identifier,
  • (iv) the results of each inspection, including a description and the location of any detected leak or defect, and
  • (v) the name of the person who performed each inspection and the name of their employer;
• (j) if the emissions control equipment is a pressure-vacuum vent, information on the inspections required under section 104, including
  • (i) the date of each inspection performed,
  • (ii) if an inspection was omitted or not performed within the required time limits, the reason why,
  • (iii) the results of each inspection, including a description and the location of any detected leak or defect, and
  • (iv) the name of the person who performed each inspection and the name of their employer; and
• (k) if the emissions control equipment is a vapour control system or pressure-vacuum vent, information on any detected defect of it referred to in subsection 90(3) or 105(2), including, as applicable,
  • (i) the date on which the defect is detected,
  • (ii) a description of the defect,
  • (iii) the date of which the defect is repaired,
  • (iv) a description of the repair and the results of any necessary tests or inspections that are performed to confirm whether the repair is successful,
  • (v) an indication of whether the repair was performed while the tank or loading rack on which it is installed was in service, and
  • (vi) the reasons why the defect was not repaired within the time limit set out in subsection 90(1) or 105(1), if applicable.

Tanks

110 (1) The operator of a facility must maintain, in respect of each tank at the facility designated under section 12, a record that contains the following information and any supporting documents:

• (a) the identifier of the tank;
• (b) the year of the tank’s installation and the design specifications of the tank, including
  • (i) the internal volume of the tank, calculated in accordance with section 15,
  • (ii) the height and diameter of the tank, and
  • (iii) the type and identifier of any emissions control equipment installed on the tank;
• (c) the description of each liquid stored in the tank and the dates on which the tank contained the liquid, including, in the case of a volatile petroleum liquid, its vapour pressure, benzene concentration and, if it is an oil-water mixture, VOC concentration;
• (d) if the interior of the tank is cleaned for the purposes of paragraph 7(2)(a), the value of the LEL% inside the tank, the identifier of the instrument that was used to determine that value and an indication of whether mechanical ventilation was used during that determination;
• (e) the category to which the tank was designated to belong under section 12, the date on which it was first designated, any changes made to the designation, the date on which those changes were made and the reasons for those changes;
• (f) if the tank is used as an intermittent service tank under subsection 10(1), information to establish that it has been in service for 300 hours or less per calendar year and, if applicable, the statistical or engineering analysis referred to in subsection 10(3);
• (g) if the tank is used as a surge tank under subsection 11(1), a description of the abnormal operating conditions and the liquids transferred into the tank and the dates on which the liquids were transferred to or removed from the tank;
• (h) a maintenance plan for the tank that includes
  • (i) the dates of any scheduled maintenance and an indication of whether the tank will be removed from service during the maintenance, and
  • (ii) the latest allowable dates of the next inspections under subsections 91(1), 93(1), 94(1) and 95(1) and sections 96 and 97, as applicable, considering any applicable reduction of an inspection interval under section 99;
• (i) the dates and the duration of any periods during which the tank’s internal floating roof or external floating roof was resting on a support structure or suspended under subsection 61(2) or (3) or 70(2), as applicable;
• (j) information on the inspections of the tank or its internal floating roof or external floating roof required under subsection 91(1), 92(7), 93(1), 94(1) or 95(1) or sections 96 or 97, as applicable, including
  • (i) the date of each inspection performed,
  • (ii) if an inspection was omitted, the reason why and an indication of whether the inspection was omitted under subsection 91(2),
  • (iii) if an inspection was not performed within the applicable time limit, the reason why and an indication of whether the inspection was delayed under subsection 94(2),
  • (iv) the provision of these Regulations under which each inspection was performed,
  • (v) the results of each inspection, including a description and the location of any detected defects,
  • (vi) for each inspection of an internal floating roof,
    • (A) the measured LEL% in the space above the internal floating roof and the baseline LEL% calculated under section 92,
    • (B) the identifier of the instrument that was used to measure the LEL%,
    • (C) an indication of whether the measurement was part of a second inspection under subsection 92(7),
    • (D) the estimated wind speed at the time that the measurement was taken, and
    • (E) the volume of liquid in the tank at the time that the measurement was taken and eight hours before that time, and
  • (vii) the name of the person who performed each inspection, the name of their employer, and in the case of an inspection performed under subsection 93(1) or section 96, proof demonstrating that the person holds the certificate required under section 98;
• (k) testing and inspection records referred to in paragraph 93(2)(a) that are used to establish when the 20-year period referred to in subsection 93(1) begins, if applicable;
• (l) information on any detected defect referred to in subsection 100(5) or 101(1) of the tank or its internal floating roof or external floating roof, including, as applicable,
  • (i) the date on which the defect was detected,
  • (ii) a description of the defect,
  • (iii) the date on which the defect was repaired,
  • (iv) a description of the repair and the results of any necessary tests or inspections that are performed to confirm whether the repair is successful,
  • (v) if the defect was not repaired within the applicable time limit set out in section 100, the reason why,
  • (vi) if the tank’s internal floating roof or external floating roof has a defect referred to in subsection 101(1)
    • (A) the date on which the operator ceased filling the tank with volatile petroleum liquid,
    • (B) the date on which the operator emptied the tank of all volatile petroleum liquid in accordance with paragraph 101(2)(a), or the date on which the operator equipped the tank with a temporary vapour control system in accordance with paragraph 101(2)(b) and the date on which use of the temporary system began, as applicable, and
    • (C) the factors taken into account in the choice of measures referred to in subsection 101(2), and
  • (vii) if a rim seal of the tank has a defect, information on any determinations made for the purposes of subsections 100(3) and (4), including
    • (A) the date on which the person referred to in paragraph 100(3)(b) determined that the tank is free of any other defects, the name of that person, the name of their employer and proof demonstrating that the person holds the certificate required under that paragraph,
    • (B) the date on which the operator determined under subsection 100(4) that the defect of the rim seal could not be repaired while the tank is in service, if applicable, and
    • (C) an indication of whether the repair was attempted while the tank is in service;
• (m) a copy of any VOC emissions minimization plan developed under subsection 103(1) in respect of the tank, including an indication of any deviations to the measures included in the plan and the date on which the plan was completed;
• (n) if the operator implements an extended repair plan in respect of the tank under subsection 106(1) for one of the reasons referred to in paragraph 106(1)(b) or (c), the date on which the operator ceased filling the tank with any volatile petroleum liquids; and
• (o) an indication of whether the tank has been designated under subsection 125(1) as a deferred application tank and, if applicable, the expected date on which the designation will no longer apply to the tank.

Other tanks

(2) The operator must maintain, in respect of each tank at the facility not designated under section 12 that has an internal volume greater than or equal to 150 m³, a record that contains the following information and any supporting documents:

• (a) the identifier of the tank;
• (b) the internal volume of the tank;
• (c) the height and diameter of the tank; and
• (d) a description of the liquid stored in the tank, if any.

Fenceline monitoring program

111 If the operator of a facility continues, under section 44, to use an internal floating roof or external floating roof instead of a vapour control system to control VOC emissions, the operator must maintain a record that contains the following information and any supporting documents in relation to the fenceline monitoring program at the facility:

• (a) a diagram of the facility that includes the property boundary, fenceline, sampling locations, petroleum processing equipment, tanks, loading racks and wastewater treatment areas;
• (b) a description of the analysis used to select the fenceline, including the method used, the factors taken into account and the calculations, if any, carried out;
• (c) the number of sampling tubes, their location at the fenceline and a description of the analysis used to select their locations including the method used, the factors taken into account and the calculations, if any, carried out; and
• (d) for each sampling period,
  • (i) the start and end dates of the sampling period,
  • (ii) the benzene concentration measured at each sampling location, together with the benzene concentration measured in each field blank and in each duplicate sample,
  • (iii) meteorological data from a meteorological station located at the facility or within 40 km of the fenceline, including wind speed, wind direction, temperature and barometric pressure, measured on an hourly basis,
  • (iv) an indication of whether data collected during the sampling period was excluded under subsection 45(3), if applicable, and
  • (v) the arithmetic average of the benzene concentration measured during the 26 most recent sampling periods at each sampling location, taking into account any replacements made in accordance with subsection 45(4).

Loading racks

112 (1) The operator of a facility must maintain, in respect of each loading rack at the facility designated under section 13 other than one designated under paragraph 13(c), a record that contains the following information and any supporting documents:

• (a) the identifier of the loading rack;
• (b) the year of the loading rack’s installation and the design specifications of the loading rack, including the type and identifier of any emissions control equipment installed on the loading rack;
• (c) the types of vehicles loaded with the loading rack;
• (d) information on each volatile petroleum liquid that is loaded with the loading rack, including
  • (i) a description of the volatile petroleum liquid, including its vapour pressure, benzene concentration and, if it is an oil-water mixture, VOC concentration,
  • (ii) the volume of the volatile petroleum liquid that is loaded each day while the emissions control equipment is in service, and
  • (iii) the volume of the volatile petroleum liquid that is loaded each day while the emissions control equipment is not in service;
• (e) the category to which the loading rack was designated to belong under section 13, the date on which it was first designated, any changes made to the designation, the date on which those changes were made and the reasons for those changes;
• (f) the total volume of liquids switch loaded with the loading rack in each calendar year without the use of a vapour control system or a declaration from the authorized official that less than 30% of the total volume of liquids loaded in the calendar year with the loading rack was switch loaded without the use of a vapour control system; and
• (g) an indication of whether the loading rack has been designated under subsection 125(1) as a deferred application loading rack and, if applicable, the expected date on which the designation will no longer apply to the loading rack.

Other loading racks

(2) The operator must maintain a record containing the following information and supporting documents in respect of each loading rack at the facility not designated under section 13 and each loading rack designated under paragraph 13(c):

• (a) the identifier of the loading rack;
• (b) the description of the liquids loaded with the loading rack, if any; and
• (c) in the case of a loading rack designated under paragraph 13(c), the loading factor of the loading rack or a declaration from the authorized official that the total loading factor does not exceed 0.04.

Loading factors

(3) The operator must maintain a record that contains the total loading factor and maximum daily loading factor of the facility and any supporting documents.

Modification of loading factor

(4) The operator must maintain a record of any modification under subsection 16(2) of the calculation of the loading rack’s loading factor that contains the following information and any supporting documents:

• (a) the identifier of the loading rack;
• (b) the types of vehicles loaded with the loading rack;
• (c) a description of the exceptional event that led to the modification;
• (d) the start and end dates of the exceptional event;
• (e) the start and end dates of the period during which the exceptional event caused the volume of volatile petroleum liquids loaded with the loading rack to increase;
• (f) the volume of each volatile petroleum liquid loaded per day during the period referred to in paragraph (e);
• (g) the volume of each volatile petroleum liquid loaded as determined in accordance with subparagraph 1(c)(iv) of Schedule 1; and
• (h) a document setting out the reasons why the authorized official made the determination referred to in subsection 16(2), dated and signed by the authorized official.

Vehicle-to-vehicle loading

(5) The operator must maintain a record of the dates on which vehicle-to-vehicle loading is performed at the facility, the types of vehicles used for the loading and the distance from the loading location to the nearest occupied building.

Sample of liquids

113 The operator of a facility must maintain, in respect of each sample taken at the facility for the purposes of determining the vapour pressure, benzene concentration or VOC concentration of a liquid stored in a tank or loaded with a loading rack, a record that contains the following information and any supporting documents:

• (a) a description of the liquid;
• (b) the identifier of the tank or loading rack from which the sample was taken;
• (c) the date on which the sample was taken, the name of the person who took the sample, the name of their employer and the sampling method used;
• (d) the date on which the sample was tested, the name of the person who performed the test, the name of their employer and the test method used to determine the vapour pressure, the benzene concentration or the VOC concentration of the liquid;
• (e) the test conditions and the results of the test; and
• (f) any information needed to identify the sample and link it to the test results.

Instrument and continuous monitoring device

114 The operator of a facility must maintain a record that contains the following information and any supporting documents in respect of each instrument or continuous monitoring device used at the facility for the purposes of these Regulations:

• (a) in the case of an instrument, its the identifier;
• (b) the design specifications of the instrument or continuous monitoring device; and
• (c) the results of each calibration or test performed on the instrument or continuous monitoring device, the date on which it was performed, the name of the person who performed it and the name of their employer.

Measurements and calculations

115 An operator must maintain a record, along with any supporting documents, of each measurement or calculation that is used to determine the value of a variable of a formula set out in these Regulations, including the methodology that is used to determine that value.

Units of measurement

116 Unless otherwise specified, all units of measurement used in any record, notice, plan or report required or application submitted under these Regulations must be expressed using the following units:

• (a) in the case of the volume of a tank, m³;
• (b) in the case of the volume of a fluid, standard m³;
• (c) in the case of the benzene concentration of a liquid, % by weight;
• (d) in the case of VOC concentration of a liquid, % by weight;
• (e) in the case of vapour pressure, kPa;
• (f) in the case of the benzene concentration measured under a fenceline monitoring program, μg/m³; and
• (g) in the case of a distance, metric units.

Person performing sampling

117 (1) The operator of a facility must maintain a record that contains the following information and any supporting documents in respect of any person performing sampling at the facility for the purposes of these Regulations:

• (a) the name, title and business address of the person and the name of their employer;
• (b) an indication of whether the person meets the requirements set out in at least one of paragraphs 22(a) to (c) and which one;
• (c) if the person is a qualified professional, their qualifications; and
• (d) in the case of a person who meets the requirements set out in paragraph 22(b) or (c), the qualifications of the qualified professional referred to in that paragraph.

Person performing testing

(2) The operator must maintain a record that contains the following information and any supporting documents in respect of any person performing testing required under sections 23 to 25:

• (a) the name, title and business address of the person and the name of their employer;
• (b) an indication of whether the person meets the requirements set out in at least one of paragraphs 29(a) to (c) and which one;
• (c) if the person is a qualified professional, their qualifications; and
• (d) in the case of a person who meets the requirements set out in paragraph 29(b) or (c), the qualifications of the qualified professional referred to in that paragraph.

Training — emissions control equipment

(3) The operator must maintain a record that contains the following information and any supporting documents in respect of any training completed by any person in relation to the activities referred to in section 35:

• (a) the name, title and business address of the person and the name of their employer;
• (b) the name of the entity that provides the training;
• (c) a description of the training; and
• (d) the date on which the training is completed.

Person designated as operator

118 If the operator is a person who is designated under a written agreement referred to in paragraph (b) of the definition operator in subsection 1(1), the operator must keep a record of that agreement.

Person designated as authorized official

119 If the authorized official is a person who is the subject of a designation referred to in the definition authorized official in subsection 1(1), the operator must keep a record of that designation.

Notices, plans and reports

120 An operator must maintain a record, including any supporting documents, of any notices, plans or reports required under these Regulations.

Information submitted electronically

121 (1) Any application, notice, plan or report submitted to the Minister under these Regulations must be submitted, dated and signed electronically by an authorized official in the form and format specified by the Minister.

Paper submission

(2) If no electronic form and format is specified or it is impractical to submit the application, notice, plan or report electronically in accordance with subsection (1) because of circumstances beyond the control of the operator , they must be submitted on paper, and dated and signed by an authorized official in the form and format, if any, specified by the Minister. However, if no form and format have been so specified by the Minister, they may be in any form and format.

Subsection 124(3)

(3) Despite subsections (1) and (2), the dated signature of the authorized official is not required when notifying the Minister under subsection 124(3) of any change to the information provided.

Minister’s request — records

122 (1) On the Minister’s request, the operator of a facility must, within 30 days after the day on which the request is made, provide the Minister with a copy of any records that the operator is required to maintain under these Regulations.

Minister’s request — sample

(2) The operator must make available to the Minister and, on the Minister’s request, provide the Minister, at an address and in a manner specified in the request, with a sample of any liquid that is contained in a tank or that is loaded with a loading rack at the facility.

Retention of Records

Information recorded

123 (1) Except as otherwise provided in these Regulations, the operator of a facility must ensure that all information that they are required to record under these Regulations, is recorded as soon as feasible but no later than 30 days after the information to be recorded becomes available.

Period

(2) The operator must ensure that any record that they are required to maintain under these Regulations is retained for at least six years after the day on which the record is made or updated.

Inspections — subsection 93(1)

(3) Despite subsection (2), the records of any inspection of the interior of a tank and an internal floating roof performed under subsection 93(1) and any repair made as a result of the inspection must be retained until the day on which the next inspection is performed under that section.

Electronically readable format

(4) Records that are retained electronically must be in an electronic format that is compatible with the format that is used by the Minister.

Location of records

(5) The records must be retained at the facility or at any other place in Canada where the records can be inspected.

Language

(6) All records that are required to be maintained under these Regulations must be in English or French or, if in another language, be accompanied by a translation into English or French and an affidavit attesting to the accuracy of the translation.

Registration of Facility

Report of registration

124 (1) An operator must submit to the Minister, for each facility that they operate, a report of registration that contains the information referred to in Schedules 10 and 11.

Time limit — submission

(2) The operator must submit the report of registration within 30 days after the day on which the facility begins to operate or within 120 days after the day on which these Regulations come into force, whichever is later.

Change of information

(3) The operator must notify the Minister of any change to the information referred to in items 1 to 3 and 7 in Schedule 11 within 15 days after the day on which the change occurs.

Update

(4) Each calendar year, the operator must, within 30 days after the anniversary of the day on which these Regulations come into force, submit to the Minister an update of the information referred to in Schedule 10 and in items 1 to 9 and 12 of Schedule 11 or notify the Minister that there has been no change to the information.

Deferred Application to Existing Tanks and Existing Loading Racks

Designation

125 (1) Subject to subsections (2), (3) and (4) and sections 126 to 130, the operator of a facility may designate an existing tank as a deferred application tank or existing loading rack as a deferred application loading rack and extend the non-application of the requirements referred to in section 135, for as long as the designation applies to the tank or loading rack.

High benzene

(2) A designation referred to in subsection (1) must not be applied to an existing high benzene tank or to an existing high benzene loading rack.

At least two existing tanks

(3) An existing tank at a facility may be designated under subsection (1) only if at least two existing tanks at the facility meet one of the following criteria:

• (a) they have been equipped with an internal floating roof after the day on which these Regulations come into force;
• (b) they have been equipped with a vapour control system after the day on which these Regulations come into force; or
• (c) they have been removed from service to complete a repair under section 100 or 101 after the day on which these Regulations come into force.

At least one existing loading rack

(4) In the case of a facility with a total loading factor that is greater than or equal to 8 on the day on which these Regulations come into force, an existing loading rack at that facility may be designated under subsection (1) only if at least one existing loading rack at the facility has been equipped with a vapour control system after that day.

Fourth year — existing tanks

126 (1) In the fourth year after the day on which these Regulations come into force, the number of existing tanks at a facility that are designated under subsection 125(1) must not exceed the lesser of the following values:

• (a) 20%, rounded up to the nearest whole number, of the total number of tanks indicated in the report of registration of the facility in accordance with item 11 of Schedule 11, and
• (b) 12.

Two existing loading racks

(2) In the fourth year after the day on which these Regulations come into force, the number of existing loading racks at a facility that are designated under subsection 125(1) must not exceed two.

Fifth year — existing tanks

127 (1) In the fifth year after the day on which these Regulations come into force, the number of existing tanks at a facility that are designated under subsection 125(1) must not exceed the lesser of the following values:

• (a) 15%, rounded up to the nearest whole number, of the total number of tanks indicated in the report of registration of the facility in accordance with item 11 of Schedule 11, and
• (b) nine.

One existing loading rack

(2) In the fifth year after the day on which these Regulations come into force, the number of existing loading racks at a facility that are designated under subsection 125(1) must not exceed one.

Sixth year — existing tanks

128 (1) In the sixth year after the day on which these Regulations come into force, the number of existing tanks at a facility that are designated under subsection 125(1) must not exceed the lesser of the following values:

• (a) 10%, rounded up to the nearest whole number, of the total number of tanks indicated in the report of registration of the facility in accordance with item 11 of Schedule 11, and
• (b) six.

No existing loading racks

(2) Beginning in the sixth year after the day on which these Regulations come into force, there must not be any existing loading racks at a facility that are designated under subsection 125(1).

Seventh year — existing tanks

129 In the seventh year after the day on which these Regulations come into force, the number of existing tanks at a facility that are designated under subsection 125(1) must not exceed the lesser of the following values:

• (a) 5%, rounded up to the nearest whole number, of the total number of tanks at the facility indicated in the report of registration of the facility in accordance with item 11 of Schedule 11, and
• (b) three.

Eighth year — no existing tanks

130 Beginning in the eighth year after the day on which these Regulations come into force, there must not be any existing tanks at a facility that are designated under subsection 125(1).

Transitional Provisions

Existing vapour control systems

131 (1) Despite subsection 33(2), the requirements set out in sections 50 to 55, subsection 58(1), sections 59 and 86 to 90 do not apply to existing vapour control systems until the first anniversary of the day on which these Regulations come into force.

Exception

(2) Despite subsection 33(2), the requirements set out in section 36 and subsection 58(2) do not apply to existing vapour recovery systems or existing vapour destruction systems until the third anniversary of the day on which these Regulations come into force.

Existing tanks — internal floating roofs

132 Despite subsection 33(2), the requirements set out in sections 62 to 63, subsection 64(2) and sections 66 to 68 do not apply to existing tanks equipped with an internal floating roof that was installed before the day on which these Regulations come into force until the day on which

• (a) an inspection of the tank is performed in accordance with subsection 93(1);
• (b) the time limit for the inspection of the tank under subsection 93(1) has passed; or
• (c) in the case of a tank that is removed from service, the tank is returned to service.

First anniversary — existing tanks

133 Despite subsection 33(2), the requirements set out in sections 78, 79, 91, 92 and 94 to 96, subsections 100(1) to (5) and sections 103 to 105 do not apply to existing tanks until the first anniversary of the day on which these Regulations come into force.

Existing high benzene tanks

134 (1) Despite subsection 33(1) and subject to subsections (2) and (3), the requirements set out in section 38 do not apply to existing high benzene tanks until the first anniversary of the day on which these Regulations come into force.

Three or more tanks

(2) Subject to subsection (3), if, on the day on which these Regulations come into force, a facility has three or more existing high benzene tanks that contain a liquid with a benzene concentration greater than 20% by weight and that do not meet the requirements set out in section 38, the operator of that facility must

• (a) ensure that on the first anniversary of that day, at least two of the existing high benzene tanks meet the requirements of section 38 and that the remainder of the existing high benzene tanks are no longer high benzene tanks or are equipped with a temporary vapour control system; and
• (b) ensure that on the second anniversary of the day on which these Regulations come into force, all of the existing high benzene tanks meet the requirements of section 38 or are no longer high benzene tanks.

Exception — Interim Order

(3) If an existing high benzene tank is located at a facility that was subject to the Interim Order Respecting Releases of Benzene from Petrochemical Facilities in Sarnia, Ontario made by the Minister on May 16, 2024 and published in Part 1 of the Canada Gazette on May 21, 2024, the requirements of section 38 apply to that existing high benzene tank beginning on the day on which these Regulations come into force.

Existing high benzene loading racks

(4) Despite subsection 33(1), the requirements under section 42 do not apply to existing high benzene loading racks until the first anniversary of the day on which these Regulations come into force.

Third anniversary — existing tanks

135 (1) Despite subsection 33(1), the requirements set out in sections 38 to 40 do not apply to existing tanks, other than existing high benzene tanks, until the third anniversary of the day on which these Regulations come into force.

Existing tanks — external floating roofs

(2) Despite subsection 33(2), the requirements set out in sections 71 and 72, subsections 73(2) to (4) and sections 75 to 77 do not apply to existing tanks equipped with an external floating roof that was installed before the day on which these Regulations come into force until the third anniversary of that day.

Existing loading racks

(3) Despite subsection 33(1) and subject to section 136, the requirements set out in section 42 do not apply to existing loading racks, other than existing high benzene loading racks, until the third anniversary of the day on which these Regulations come into force.

Fourth anniversary

136 The requirements set out in section 42 do not apply to existing loading racks that are used to load to ships or transport barges, other than existing high benzene loading racks, until the fourth anniversary of the day on which these Regulations come into force.

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

137 The schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) ^{footnote 1} is amended by adding the following in numerical order:

Item	Column 1 Regulations	Column 2 Provisions
44	Reduction in the Release of Volatile Organic Compounds (Storage and Loading of Volatile Petroleum Liquids) Regulations	(a) subsections 33(1) and (2) (b) section 35 (c) section 36 (d) section 38 (e) section 39 (f) section 40 (g) section 41 (h) section 42 (i) subsection 43(3) (j) section 46 (k) section 49 (l) section 50 (m) section 52 (n) section 53 (o) subsection 54(1) (p) subsection 56(1) (q) section 57 (r) section 58 (s) section 59 (t) section 60 (u) subsection 61(1) (v) section 62 (w) section 63 (x) subsection 64(1) (y) subsections 65(2) and (3) (z) subsection 66(1) (z.01) section 67 (z.02) section 68 (z.03) section 69 (z.04) subsection 70(1) (z.05) section 71 (z.06) section 72 (z.07) subsection 73(1) (z.08) subsection 74(2) (z.09) subsection 75(1) (z.10) section 76 (z.11) section 77 (z.12) section 78 (z.13) section 79 (z.14) subsections 86(1) and (2) (z.15) subsection 90(1) (z.16) subsection 91(1) (z.17) section 93 (z.18) subsection 94(1) (z.19) subsection 95(1) (z.20) section 96 (z.21) subsections 100(1), (3) and (4) (z.22) section 101 (z.23) subsection 103(1) (z.24) section 104 (z.25) section 105

Coming into Force

Registration

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

120th day after registration

(2) Subsection 43(3) and section 49 come into force on the 120th day after the day on which these Regulations are registered.

SCHEDULE 1

(Section 16 and paragraph 112(4)(g))

Calculation of Loading Factors

Total Loading Factor

1 The method to calculate the total loading factor of a facility for the previous calendar year is as follows:

• (a) determine the highest vapour pressure and the highest benzene concentration of each volatile petroleum liquid loaded at the facility;
• (b) for each volatile petroleum liquid and each loading recipient referred to in column 1 of Table 3 to this section, calculate the loading factor in accordance with the formula

  V ÷ (F_benz × F_VP × F_load × 25 000)

  where

  V

  is the volume of the volatile petroleum liquid loaded, as calculated in accordance with the method set out in paragraph (c),

  F_benz

  is the value set out in column 2 of Table 1 to this section for the benzene concentration determined under paragraph (a),

  F_VP

  is the value set out in column 2 of Table 2 to this section for the vapour pressure determined under paragraph (a), and

  F_load

  is the value set out in column 2 of Table 3 to this section for the loading recipient referred to in column 1;

• (c) determine the volume of each volatile petroleum liquid, in standard m3, that was loaded without the use of a vapour control system during the previous calendar year, taking into account the following modifications, if applicable:
  • (i) if no volatile petroleum liquid was loaded at the facility during the previous calendar year, the volume that is expected to be loaded during the current calendar year must be determined,
  • (ii) if 30% or more of the total volume of liquids loaded with the loading rack was switch loaded without the use of a vapour control system, the volume of any liquid switch loaded without the use of a vapour control system must be counted as the loading of a volatile petroleum liquid with F_benz equal to 2.4 and F_VP equal to 2.8,
  • (iii) if a loading rack was equipped with a vapour control system in accordance with section 42 during the previous or current calendar year, the volume of volatile petroleum liquid loaded with that loading rack is not included in the calculation of the volume, and
  • (iv) in the case of an exceptional event referred to under subsection 16(2), the volume loaded with the loading rack during the period in which the exceptional event caused the volume of volatile petroleum liquids loaded with the loading rack to increase may be replaced with the average volume loaded with that loading rack during the same period in the most recent year during which no such event occurred or, if data are not available for any such year, an estimate of the volume that would be loaded during the same period under normal operating conditions; and
• (d) calculate the sum of the loading factors calculated under paragraph (b), which constitutes the facility’s total loading factor.

TABLE 1

Item	Column 1 Benzene Concentration (% by weight)	Column 2 Fbenz
1	Less than 0.5	2.4
2	0.5 to 1.0	1 table c2 note 1
3	1.1 to 2.0	0.6
4	2.1 to 10.0	0.2
5	Greater than 10	0.02
Table c2 note(s) Table c2 note 1 Use Fbenz = 1 for gasoline regardless of actual benzene concentration Return to table c2 note 1 referrer

TABLE 2

Item	Column 1 Vapour Pressure (kPa)	Column 2 FVP
1	3.5 to 10.0	1
2	10.1 to 35.0	2.8
3	35.1 to 65	1 table c3 note 1
4	Greater than 65	0.4
Table c3 note(s) Table c3 note 1 Use FVP = 1 for gasoline regardless of actual vapour pressure Return to table c3 note 1 referrer

TABLE 3

Item	Column 1 Loading Recipient	Column 2 Fload
1	Truck	1
2	Railcar	1
3	Ship or transport barge	1.5
4	Vehicle other than truck, railcar, ship or transport barge	1
5	Fixed roof tank	1

Maximum Daily Loading Factor

2 The method to calculate the maximum daily loading factor of a facility is as follows:

• (a) determine the highest vapour pressure and the highest benzene concentration of each volatile petroleum liquid loaded at the facility;
• (b) for each day in the previous calendar year, calculate the daily loading factor for each volatile petroleum liquid and each loading recipient referred to in column 1 of the table to this section in accordance with the formula

  V_D ÷ F_D

  where

  V_D

  is the daily volume of the volatile petroleum liquid, in standard m³, loaded to the loading recipient with a loading rack not equipped with a vapour control system in accordance with section 42, and

  F_D

  is the value set out in column 3 of the table to this section for the loading recipient set out in column 1 and the benzene concentration referred to in column 2;

• (c) for each day in the previous calendar year, calculate the sum of the daily loading factors calculated under paragraph (b); and
• (d) determine the highest value calculated under paragraph (c) for any day in the previous calendar year, which is the facility’s maximum daily loading factor.

TABLE

Item	Column 1 Loading Recipient	Column 2 Benzene Concentraton (% by weight)	Column 3 FD
1	Truck, railcar, fixed roof tank or vehicle other than ship or transport barge	(1) Less than 0.5	(a) 10 000 if vapour pressure is less than 35 kPa (b) 2 000 if vapour pressure is greater than or equal to 35 kPa
		(2) 0.5 to 1.0	500 table d1 note 1
		(3) Greater than 1	30
2	Ship or transport barge	(1) Less than 0.5	(a) 15 000 if vapour pressure is less than 35 kPa (b) 4 000 if vapour pressure is greater than or equal to 35 kPa
		(2) 0.5 to 1.0	1 100 table d1 note 2
		(3) Greater than 1	50
Table d1 note(s) Table d1 note 1 Use FD = 500 for gasoline regardless of actual benzene concentration Return to table d1 note 1 referrer Table d1 note 2 Use FD = 1 100 for gasoline regardless of actual benzene concentration Return to table d1 note 2 referrer

SCHEDULE 2

(Subsection 30(5))

Information in Relation to an Application for the Use of Alternative Test Methods

• 1 The name of the operator.
• 2 The name of the facility where the alternative test method would be used.
• 3 The name, title, civic and postal addresses, telephone number and email address of a contact person at the facility.
• 4 The name, title, civic and postal addresses, telephone number and email address of the authorized official.
• 5 The name and a description of the alternative test method and a copy of the method if it is not publicly available.
• 6 The test method set out in sections 23 to 25 that the alternative test method would replace.
• 7 The purpose set out in paragraphs 30(1)(a) to (c) for which an application is made.
• 8 A description of the situations in which the alternative test method would be used, including any limitations on when it would be used.
• 9 The evidence demonstrating that the conditions set out in subsection 30(2) would be met.
• 10 The test method set out in paragraph 30(3)(a) and (b) that is used to determine the equivalency of the alternative test method.
• 11 The date on which the operator proposes to begin using the alternative test method.

SCHEDULE 3

(Subsections 47(2) to (5), 48(1) and 49(2))

Information in Relation to Existing High Benzene Tanks

PART 1
Information in Relation to the Fenceline Monitoring Program

• 1 The name of the operator.
• 2 The name of the facility.
• 3 The name, title, civic and postal addresses, telephone number and email address of a contact person at the facility.
• 4 The name, title, civic and postal addresses, telephone number and email address of the authorized official.
• 5 The type of fenceline monitoring program that has been established at the facility.
• 6 The analysis used to select the fenceline, including the method used, the factors taken into account and the calculations, if any, carried out in the course of the analysis.
• 7 The sampling locations at the fenceline, the number of sampling tubes and a description of the analysis used to determine those locations and that number, including the method used, the factors taken into account and the calculations, if any, carried out in the course of the analysis.
• 8 A diagram of the facility that includes the property boundary, fenceline, sampling locations, petroleum processing equipment, tanks, loading racks and wastewater treatment areas.
• 9 For each sampling period,
  • (a) the start and end dates of the sampling period;
  • (b) the benzene concentration measured at each sampling location, together with the benzene concentration measured in each field blank and in each duplicate sample;
  • (c) an indication of whether the data collected during the sampling period was excluded in accordance with subsection 45(3); and
  • (d) the arithmetic average of the benzene concentration measured for the 26 most recent sampling periods at each sampling location, taking into account any replacements made in accordance with subsection 45(4).

PART 2
Information in Relation to the Exceedance Report

• 1 The name of the operator of the facility.
• 2 The name of the facility.
• 3 The name, title, civic and postal addresses, telephone number and email address of a contact person at the facility.
• 4 The name, title, civic and postal addresses, telephone number and email address of the authorized official.
• 5 For each sampling period that began after the last sampling period that was included in a preceding report submitted to the Minister under subsections 47(2) and (4) or 48(1),
  • (a) the start and end dates of the sampling period;
  • (b) the benzene concentration measured at each sampling location, in each field blank and in each duplicate sample;
  • (c) an indication of whether the data collected during the sampling period was excluded in accordance with subsection 45(3); and
  • (d) the arithmetic average of the benzene concentration measured for the 26 most recent sampling periods at each sampling location, taking into account any replacements made in accordance with subsection 45(4).
• 6 The following information including any supporting documents:
  • (a) the reasons why the operator believes the exceedance occurred;
  • (b) a description and the approximate location of any benzene emission sources outside the facility that may have affected the benzene concentrations measured at the facility during the sampling periods referred to in item 5 of this Part; and
  • (c) a description, as well as the dates and locations, of any events that may have affected benzene concentrations measured at the facility during the sampling periods referred to in item 5 of this Part.

PART 3
Information in Relation to the Action Plan

• 1 The name of the operator of the facility.
• 2 The name of the facility.
• 3 The name, title, civic and postal addresses, telephone number and email address of a contact person at the facility.
• 4 The name, title, civic and postal addresses, telephone number and email address of the authorized official.
• 5 The identifier of the tank and of the vapour control system installed on the tank, if any.
• 6 A description of the liquid stored in the tank, including the volume and benzene concentration,
• 7 If applicable, the most recent value of the LEL% in the space above the internal floating roof of the tank.
• 8 The activities that the operator intends to undertake in respect of the action plan referred to under subsection 49(1).
• 9 A description of the planned steps in relation to the activities, the start and end dates of the steps and an indication of which of those steps are expected to cause VOC emissions.
• 10 The measures that will be taken in relation to the planned steps to minimize or manage VOC emissions and the dates on which the measures will be taken.
• 11 A description of any measures that will be taken to monitor VOC emissions and the expected timelines to perform them.
• 12 Any planned notifications to the Minister, including notifications of the completion of each planned step, of any deviations from the plan and of the results of the VOC emissions monitoring.

SCHEDULE 4

(Subsections 65(1) and 74(1), paragraph 93(1)(a), subsection 95(1), paragraph 96(a) and section 97)

Measuring Seal Gaps of Floating Roof Tanks

Control Conditions

1 The control conditions to be used when measuring the seal gaps of a floating roof tank are as follows:

• (a) a set of uniform cylindrical probes of varying diameters that meet the following criteria must be used:
  • (i) the smallest probe must have a diameter of 0.3 cm,
  • (ii) one of the probes must have a diameter of 4 cm if a primary seal gap is being measured or a diameter of 1.3 cm if a secondary seal gap is being measured, and
  • (iii) each probe must have a diameter that is less than double the diameter of the next smallest probe;
• (b) the liquid level in the tank must not change;
• (c) if the tank is an external floating roof tank, all seal gap measurements must be taken while the floating roof is freely floating on the surface of the liquid and not when it is resting on a support structure or suspension system; and
• (d) if a primary seal gap is being measured, any secondary seal or cover that restricts access to the primary seal must be pulled away from the tank wall, removed or otherwise positioned such that it will not interfere with the measurement.

Procedure

2 The procedure to be followed to measure the seal gaps of a floating roof tank consists of the following steps taken in the following order:

• (a) identify all seal gaps on the circumference of the tank by passing a probe that has a diameter of 0.3 cm between the seal and the wall of the tank without forcing or binding the probe against the seal;
• (b) determine the length of each seal gap by measuring, in centimetres, the circumferential distance along the tank wall between the two extreme opposite ends of the seal gap;
• (c) determine the surface area of each seal gap by using successively larger probes to measure, in centimetres, the width of the gap between the seal and the wall of the tank and then multiplying each width by its respective length determined under paragraph (b) (if the width of the seal gap at any point is larger than the diameter of one probe but smaller than the diameter of the next probe, then the width must be linearly interpolated using the measurements of those two probes);
• (d) determine and record the width of the widest seal gap;
• (e) calculate the sum of the individual surface areas determined under paragraph (c) for all seal gaps identified under paragraph (a); and
• (f) divide the total surface area determined under paragraph (e) by the inside diameter of the tank and record the result in cm² per m.

Other Instruments

3 Despite paragraphs 1(a) and 2(c), an instrument with a single probe not larger than 0.3 cm may be used to measure the seal gaps if it can measure gaps ranging in size from 0.3 cm to 4 cm with a margin of error less than half the diameter of the seal gap.

SCHEDULE 5

(Subsection 80(3))

Information in Relation to a Permit Application for the Use of Alternative Emissions Control Equipment

• 1 The name of the operator of the facility.
• 2 The name of the facility where the alternative emissions control equipment would be used.
• 3 The name, title, civic and postal addresses, telephone number and email address of a contact person at the facility.
• 4 The name, title, civic and postal addresses, telephone number and email address of the authorized official.
• 5 A technical description, including design schematics, of the alternative emissions control equipment.
• 6 A technical description of any procedures, maintenance practices or inspections that would be used to ensure the emissions control efficacy of the alternative emissions control equipment, including the frequency with which those procedures, maintenance practices or inspections would be performed and any criteria or parameters that would be evaluated during an inspection.
• 7 A description of possible defects to the alternative emissions control equipment and how the defects would be repaired.
• 8 An analysis demonstrating that the condition set out in subsection 81(1) would be met, including
  • (a) evidence that the alternative emissions control equipment controls VOC emissions during experimental tests on full-sized tanks or full-sized loading racks or on scale models, including the methods and the results of those tests;
  • (b) evidence that the alternative emissions control equipment is suitable for the weather conditions and operating environment in which it would be used;
  • (c) all supporting monitoring or measurement data, if applicable; and
  • (d) all simulations or modelling, if applicable.
• 9 The identifier of any tank on which the alternative emissions control equipment would be used and that tank’s most recent designation under section 12, if any.
• 10 The identifier of any loading rack on which the alternative emissions control equipment would be used and that loading rack’s most recent designation under section 13, if any.
• 11 The dates on which the operator proposes to install and beginusing the alternative emissions control equipment.

SCHEDULE 6

(Subsection 91(3))

Measuring VOC Vapour Concentration in Tanks Equipped with an Internal Floating Roof

Control Conditions

1 The control conditions to be used when measuring the VOC vapour concentration in the space between the fixed roof and the internal floating roof of a tank equipped with an internal floating roof are as follows:

• (a) the volume of liquid in the tank must not be reduced by more than 25% of the tank’s total liquid capacity during the eight-hour period before the measurement is taken unless the tank has a continual flow of liquid while the tank is operating under normal conditions, in which case the measurement must be taken during a period of normal operating conditions;
• (b) the wind speed must not exceed the greater of
  • (i) 10 km/h, and
  • (ii) the historical average wind speed specific to the month in which the measurement is taken, as determined at the nearest meteorological observation station to the facility, based on the most recent Canadian Climate Normals data published by the Meteorological Service of Canada, plus 5 km/h;
• (c) the measurement must be taken at a vertical distance of not less than 2 m and not more than 4 m below the fixed roof, or, if the vertical distance between the fixed roof and the floating roof is less than 3 m, at half of the vertical distance between the fixed roof and the floating roof; and
• (d) the measurement must be taken at least 2 m away from any open hatches, covers or other emissions control devices through which vapours could be exchanged with the outside environment.

Procedure

2 The procedure to be followed to measure the VOC vapour concentration in the space between the fixed roof and the internal floating roof of a tank equipped with an internal floating roof consists of the following steps taken in the following order:

• (a) use an instrument referred to in subsection 26(2) of these Regulations;
• (b) record
  • (i) the type of instrument that is used,
  • (ii) the estimated wind speed at the time that the measurement is taken,
  • (iii) the volume of liquid in the tank at the time that the measurement is taken and eight hours before that time, and
  • (iv) the result of the measurement; and
• (c) if the instrument reading is in units other than LEL%, convert the value of the reading to LEL% and record the original instrument reading, the converted value and the conversion calculation.

SCHEDULE 7

(Paragraph 101(5)(a))

Information in Relation to Major Defects

• 1 The name of the operator.
• 2 The name of the facility.
• 3 The name, title, civic and postal addresses, telephone number and email address of a contact person at the facility.
• 4 The name, title, civic and postal addresses, telephone number and email address of the authorized official.
• 5 The identifier of the tank.
• 6 A description of the liquid stored in the tank when the defect was detected, including its volume in m³, vapour pressure and benzene concentration.
• 7 The date on which the defect was detected.
• 8 A description of the defect detected.
• 9 A description of all the repairs that have been completed and the dates on which they were completed and a description of all the repairs that will be made and the expected dates of those repairs.
• 10 A description of the measures that have been taken to minimize or manage VOC emissions and the dates on which those measures were taken and a description of the measures that will be taken to minimize or manage VOC emissions until the defect is repaired or the tank is removed from service and the expected dates of those measures.
• 11 If the tank was removed from service or will be removed from service, the date on which the tank was removed from service or the expected date on which it will be removed from service.

SCHEDULE 8

(Subsection 103(1))

Information in Relation to the VOC Emissions Minimization Plan

• 1 The identifier of the tank to which the plan applies.
• 2 A description of the planned steps, their start and end dates and an indication of which planned steps are expected to cause VOC emissions.
• 3 The measures that are to be taken in relation to the planned steps to minimize VOC emissions, including, if applicable, all measures that will be taken under subsection 103(2) and the dates on which the measures will be taken.

SCHEDULE 9

(Subsections 106(2) and paragraph 106(7)(a))

Information in Relation to the Extended Repair Plan

• 1 The name of the operator.
• 2 The name of the facility.
• 3 The name, title, civic and postal addresses, telephone number and email address of a contact person at the facility.
• 4 The name, title, civic and postal addresses, telephone number and email address of the authorized official.
• 5 The identifier of the tank to which the plan applies.
• 6 The reason invoked by the authorized official under subsection 106(1) requiring the development of an extended repair plan and the information supporting that reason.
• 7 A description of the liquid stored in the tank, including its vapour pressure and benzene concentration.
• 8 A description of the defect and the date on which it was detected.
• 9 The date on which the tank must be removed from service and the reason why the tank cannot be removed from service before that date.
• 10 A description of all the repairs that will be made and the expected dates of those repairs.
• 11 A description of any measures that will be taken to minimize or manage VOC emissions until the tank is removed from service and the expected dates of those measures.

SCHEDULE 10

(Section 108, subsection 124(1) and item 11 of Schedule 11)

Information in Relation to the Inventory

• 1 The date on which the inventory was last updated.
• 2 For each tank designated under section 12,
  • (a) the identifier of the tank;
  • (b) the internal volume of the tank calculated in accordance with section 15, the height and diameter of the tank and the type of roof installed on the tank;
  • (c) an indication of whether the tank is an existing tank;
  • (d) the service status of the tank under subsections 7(1) and (2) and the date on which that status began;
  • (e) an indication of whether the tank is used as an intermittent service tank under subsection 10(1);
  • (f) an indication of whether the tank is used as a surge tank under subsection 11(1);
  • (g) a description of each volatile petroleum liquid that is stored in the tank, including its benzene concentration and vapour pressure, and, if the volatile petroleum liquid is an oil-water mixture, its VOC concentration;
  • (h) the category assigned to the tank under section 12 and the date of that designation;
  • (i) if the tank is a high benzene tank, its distance from any occupied building determined in accordance with section 4;
  • (j) the type and the identifier of the emissions control equipment that is being used with respect to the tank under section 38, 39 or 40; and
  • (k) an indication of whether the tank is designated as a deferred application tank under subsection 125(1).
• 3 For each loading rack designated under section 13,
  • (a) the identifier of the loading rack;
  • (b) the types of vehicles loaded with the loading rack;
  • (c) an indication of whether the loading rack is an existing loading rack;
  • (d) the service status of the loading rack under section 8 and the date on which that status began;
  • (e) a description of each volatile petroleum liquid that is loaded with the loading rack, including its benzene concentration and vapour pressure, and, if the volatile petroleum liquid is an oil-water mixture, its VOC concentration;
  • (f) the volume of each volatile petroleum liquid loaded with the loading rack for each type of vehicle for the previous calendar year;
  • (g) the identifier of the tank being serviced by the loading rack, if applicable;
  • (h) the category assigned to the loading rack under section 13 and the date of that designation;
  • (i) the type and the identifier of the emissions control equipment that is being used with respect to the loading rack under section 42; and
  • (j) an indication of whether the loading rack is designated as a deferred application loading rack under subsection 125(1).

SCHEDULE 11

(Subsections 124(1) and (3), paragraphs 126(1)(a), 127(1)(a), 128(1)(a) and 129(a))

Information in Relation to the Report of Registration

• 1 The name and business number of the operator.
• 2 The civic address, if any, the name and the geographic coordinates of the facility, expressed in decimal degrees to five decimal places.
• 3 The name, title, civic and postal addresses, telephone number and email address of a contact person at the facility and, if any, a contact person at the operator’s head office.
• 4 The name, title, civic and postal addresses, telephone number and email address of the authorized official.
• 5 The facility’s National Pollutant Release Inventory identification number, if any.
• 6 A description of the type of facility or the type of activities that the facility is engaged in and the related North American Industrial Classification System codes.
• 7 The civic address of each location where records are retained under these Regulations if it is different from that of the facility.
• 8 A site map of the facility that includes a legend, a scale, the facility’s property boundary and the location of each tank and loading rack.
• 9 An indication of whether the facility’s property boundary is located more than 50 km from a population centre.
• 10 For each tank at the facility that is not listed in the inventory established under section 108, that has an internal volume greater than or equal to 150 m³ and that is either currently storing or capable of storing liquid,
  • (a) the identifier of the tank;
  • (b) the internal volume of the tank and the height and diameter of the tank; and
  • (c) a description of the liquid stored in the tank, if any.
• 11 The total number of tanks for which information is provided under item 10 of this Schedule and item 2 of Schedule 10 and the total storage capacity of the facility in m³.
• 12 The total loading factor and the maximum daily loading factor of the facility.
• 13 For each exceptional event referred to in subsection 16(2),
  • (a) a description of the event; and
  • (b) the start and end dates of the event.

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Issues

Petroleum liquid storage and loading operations are one of the largest sources of uncontrolled VOC releases from the petroleum and petrochemical sectors. The voluntary and mandatory measures currently in place do not sufficiently address the health and environmental risks associated with VOCs as smog precursors, nor do they adequately address the health risks of specific carcinogenic VOCs, such as benzene. It is common for multiple large facilities to be located near each other in and around urban areas, increasing the local population’s risk of exposure to elevated levels of benzene. Ambient air monitoring near some facilities has measured benzene levels that may pose a risk to human health. Given the proximity of many petroleum storage and loading facilities to Indigenous communities and other residential areas, nationally consistent regulations are necessary to protect people in Canada from the harmful effects of petroleum VOC releases from storage and loading facilities.

Background

Volatile organic compounds

VOCs are precursors to the formation of ground-level ozone and particulate matter, which are the main constituents of smog. Ground-level ozone and particulate matter — specifically fine particulate matter smaller than or equal to 2.5 micrometres in diameter (PM_2.5) — have been shown to be detrimental to human health. Exposure to these pollutants increases the risks for a wide range of adverse health effects.^{footnote 3} Because of their role as a precursor to ground-level ozone and particulate matter formation, VOCs are included in the List of toxic substances in Part 2 of Schedule 1 to the Canadian Environmental Protection Act, 1999 (CEPA).

From a human health perspective, scientific evidence indicates that short-term exposure to ground-level ozone causes a range of respiratory symptoms and is a risk factor for premature death. Some symptoms, like shortness of breath and reduced lung function, can result in hospital visits and admissions. Long-term exposure to ground-level ozone has been linked to a range of adverse health outcomes, such as asthma development, respiratory mortality and structural changes in the lungs.^{footnote 4,footnote 5} There is also extensive, robust evidence of adverse health effects associated with exposure to PM_2.5.^{footnote 6} Short-term exposure to PM_2.5 causes heart failure, asthma attacks and premature death, while long-term exposure causes premature death and likely causes lung cancer and heart and lung disease. There is no level of exposure to either ground-level ozone or PM_2.5 below which there are no risks to population health. Overall, exposure to these two pollutants results in a greater number of restricted activity days, emergency room visits, hospital admissions and premature mortality.

Environmental evidence shows that ground-level ozone may also negatively affect biochemical and physiological processes, such as photosynthesis. Consequently, plant leaf cells become injured and can die because of exposure to ground-level ozone. Harmful impacts to sensitive plant species are a particular concern for agriculture and forestry where economic viability of these industries may be adversely affected.^{footnote 7} Particulate matter may accumulate on surfaces and alter their optical characteristics, causing visible soiling and increasing cleaning requirements. It can reduce visibility by blocking and scattering the direct passage of sunlight through the atmosphere.

Benzene

Benzene is a specific VOC compound and a known human carcinogen which is included in the List of toxic substances under CEPA. Benzene is known to cause cancer, based on evidence from studies in both humans and laboratory animals. Studies examining the link between benzene and cancer have largely focused on leukemia and other cancers of blood cells. The CEPA assessment of benzene published in 1993 by the Minister of the Environment (the Minister) and the Minister of Health indicated that the examination of options to reduce benzene exposure should be a high priority and that such exposure should be reduced wherever possible.^{footnote 8} The National Pollutant Release Inventory reports that Canadian refineries, upgraders, terminals and petrochemical facilities release benzene into the surrounding environment.^{footnote 9} It is expected that releases of carcinogenic substances from these facilities could contribute to cancer risks for people in the vicinity of those facilities.

The Government of Canada’s Screening Assessment – Petroleum Sector Stream Approach: Natural Gas Condensates ^{footnote 10} concludes that inhalation exposures to evaporative emissions of natural gas condensates from rail and truck loading sites and natural gas condensate storage facilities may constitute a danger to human life or health. This danger is linked to benzene exposure, a high hazard component of natural gas condensates.

Storage and unloading at gasoline stations can pose similar emission exposure risks to local populations. A recent report from the Department of Health (Health Canada) concluded that “inhalation exposures to benzene attributable to gasoline station emissions may pose unacceptable risks to human health for the general population living in the vicinity.”^{footnote 11} Short-term exposure to elevated benzene levels near gasoline stations may also pose a risk to pregnant people and their developing fetuses.

The analysis by the Department of Environment (the Department) has shown that elevated ambient levels of carcinogenic benzene, that may pose a risk to human health, continue to be recorded in numerous communities across Canada, including Sarnia, Montréal and Edmonton. Recent air monitoring data and facility property line measurements have linked elevated benzene levels in some communities to storage and loading operations.

Related regulations

Following screening assessments under the Chemicals Management Plan^{footnote 12} that identified risks to human health, the Department, working jointly with Health Canada, developed regulations to control fugitive emissions of VOCs from the petroleum and petrochemical sectors. The Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector) were finalized in 2020. These regulations limit fugitive emissions, including carcinogenic substances such as benzene, from equipment leaks at petroleum refineries, upgraders, and petrochemical facilities that are integrated with a petroleum refinery or upgrader.

During consultations on the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector) from 2016 to 2018, some Indigenous peoples and non-governmental organizations (NGOs) commented that further action was needed to address additional sources of VOCs, including the storage and loading of petroleum liquids. The Regulations will address these additional emission sources.

There are federal regulations that apply to petroleum storage tanks, the Storage Tanks Systems for Petroleum Products and Allied Petroleum Products Regulations (the Storage Tank Regulations),^{footnote 13} promulgated in 2008 and amended in 2020 to reduce liquid leaks and spills from storage tank systems. The Storage Tank Regulations do not address pollutants emitted directly to the atmosphere, including VOC air emissions, and they regulate a wider scope of storage tanks than the Regulations, including very small storage tanks and tanks that contain non-volatile^{footnote 14} liquids, such as diesel and home fuel oil. The Storage Tank Regulations also apply only to tanks located on federal or Aboriginal land or operated by specified agencies under federal jurisdiction. Most of the facilities captured under the Storage Tank Regulations include sites that store small amounts of fuel (gasoline, diesel, jet fuel, and fuel oil) for local use.

Existing risk management measures in Canada

Two voluntary instruments issued by the Canadian Council of Ministers of the Environment (CCME) apply to the storage and loading of petroleum liquids, specifically the Environmental Code of Practice for Vapour Recovery in Gasoline Distribution Networks (CCME PN 1057) published in 1991, and the Environmental Guideline for Controlling Emissions of Volatile Organic Compounds from Aboveground Storage Tanks (CCME PN 1180) published in 1995.

Some facilities subject to these voluntary instruments are also subject to mandatory provincial or municipal measures, largely adapted from the voluntary CCME instruments. As an example, Metro Vancouver has requirements for vapour control for gasoline loading, while Quebec has requirements for storage tank design. Montréal, parts of Ontario and Newfoundland and Labrador have requirements for vapour control for gasoline loading and storage tank design, maintenance and inspection. This means terminals in these jurisdictions generally have significantly lower emission intensities than terminals in other jurisdictions where emission controls are not regulated.

VOC emissions in the upstream petroleum sector^{footnote 15} are regulated under the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector). However, these regulations do not address VOC emission risks from storage and loading activities at some upstream facilities including crude oil terminals and fractionation plants.

A number of petroleum storage and loading facilities are not covered by voluntary CCME instruments, the federal methane regulations for the upstream petroleum sector, provincial instruments, or municipal requirements, including many rail, marine, crude oil and petrochemical loading operations. The operating permits for some facilities reference the CCME guideline for tanks, however overall compliance with some components, especially the inspection requirements, is low across the sector, based on information gathered by the Department through numerous meetings with industry representatives and provincial government representatives.

The mixture of related instruments across different jurisdictions, where they exist, means that facilities are taking different approaches to mitigate VOC emissions, and monitoring data continues to show high ambient levels of benzene near liquid petroleum storage and loading facilities, despite existing measures in place. Therefore, there is no consistent standard of protection from the health risks associated with VOC emissions. The Regulations are designed to address this inconsistency by covering facilities nationwide based on risk, including activities that were not previously addressed such as rail and marine loading, crude oil loading, and liquid storage and loading at fractionation plants.

On May 16, 2024, the Minister issued the Interim Order Respecting Releases of Benzene from Petrochemical Facilities in Sarnia, Ontario (the Interim Order), that applied to certain petrochemical facilities located in Sarnia and immediately applied certain requirements from the proposed Regulations, as published in Canada Gazette, Part I on February 24, 2024, including requirements for fully closed vent systems with vapour control on certain storage tanks that store benzene. The Interim Order addressed an urgent and significant danger to human health posed by benzene emissions from petrochemical facilities in Sarnia by requiring these facilities to address emissions from all benzene storage tanks. The Interim Order was needed to protect the health of the residents of Aamjiwnaang First Nation community located in Sarnia, Ontario that have reported both acute and chronic health impacts from benzene exposure. The Interim Order was made under subsection 94(1) of CEPA and ceases to have effect after two years or on the day the Regulations are made, whichever comes first.

Emission sources

Sources of VOC emissions include storage tanks and loading racks at terminals, refineries, upgraders, petrochemical facilities, iron and steel manufacturing facilities and bulk plants that store large^{footnote 16} quantities of volatile petroleum liquids. According to the Department’s data (see Regulatory analysis section for details), total VOC emissions from these facilities were 55 841 tonnes in 2019, with approximately 63% (35 287 tonnes) from storage and loading of volatile petroleum liquids. Emissions from storage are generally in the form of evaporative emissions, due to inadequate emissions control on, and inadequate sealing of, tanks storing volatile liquids. Emissions from loading are mostly due to venting during the product transfer operation, particularly in the absence of installed emissions control equipment. Tables 1 and 2 (below) provide a summary of facilities by province and territory, and estimated VOC emissions for storage and loading operations, respectively.

Terminals include crude oil terminals^{footnote 17} and primary (refined product) terminals.^{footnote 18} Transport of petroleum to and from these facilities involves multiple modes of transport including pipelines, ships, railcars, and trucks.^{footnote 19} Primary terminals tend to be located close to more populated areas and may exist as separate, standalone facilities or integrated with petroleum refineries.

Refineries process crude oil or synthetic crude oil (SCO) and produce transportation fuels, with gasoline being the major product. They also produce diesel, home heating oils, lubricants, heavy oil, asphalt for roads, and feedstocks for petrochemical facilities. Most refined products produced in Canada serve the domestic market while some are exported, mainly to the United States.

Upgraders convert bitumen, or heavy oil into SCO and some may also produce refined petroleum products such as diesel and kerosene. Most upgrader facilities are integrated or associated with oil sand extraction processes. The majority of SCO is exported to the United States, although some is transported to domestic refineries.

Petrochemical facilities convert raw materials including refined petroleum feedstock, natural gas, or natural gas liquids into products including styrene, xylene, benzene, and butadiene. These products are sold to domestic chemical manufacturing facilities or exported, mainly to the United States.

Bulk plants^{footnote 20} are located in less densely populated regions where it is uneconomical and impractical to deliver products to end-users from primary terminals.^{footnote 21} Compared with primary terminals, bulk plants are smaller storage and distribution facilities. Bulk plants usually receive products by means of a tanker truck from a primary terminal and typically have fixed-roof storage tanks.

Iron and steel manufacturing facilities produce light oils with benzene concentrations greater than 20% as a byproduct of their processing of coal tars. The light oils are generally stored and loaded with existing vapour control systems in place. Four steel facilities in Ontario have been identified as potentially in scope of the Regulations, and existing vapour controls in place at the facilities are anticipated to meet the equipment requirements of the Regulations.

Table 1: Estimated number of facilities in scope of the Regulations by facility type and province/territory^{footnote 26}

Province/ Territory	Chemical or steel facility	Crude oil terminal	Primary terminal	Refinery	Refinery terminal	Upgrader	Bulk plant	Total	% of total facilities
NL	0	1	5	0	0	0	9	15	3.5
PE	0	0	1	0	0	0	2	3	0.7
NS	0	0	4	0	0	0	11	15	3.5
NB	0	1	3	1	0	0	5	10	2.3
QC	4	3	17	2	1	0	13	40	9.2
ON	12	6	23	5	3	0	31	80	18.4
MB	0	5	3	0	0	0	16	24	5.5
SK	0	20	2	2	0	1	33	58	13.4
AB	3	38	5	5	2	5	71	129	29.7
BC	0	5	19	2	1	0	24	51	11.8
YT	0	0	1	0	0	0	1	2	0.5
NT	0	1	2	0	0	0	3	6	1.4
NU	0	0	1	0	0	0	0	1	0.2
Total	19	80	86	17	7	6	219	434	100.0

Table 2: Estimated VOC emissions from storage and loading operations from facilities in scope of the Regulations by facility type and province/territory (tonnes, 2019)

Province/ Territory	Chemical or steel facility	Crude oil terminal	Primary terminal	Refinery	Refinery terminal	Upgrader	Bulk plant	Total
NL	0	63	1 915	0	0	0	9	1 924
PE	0	0	172	0	0	0	17	189
NS	0	0	1 095	0	0	0	95	1 190
NB	0	83	210	1 075	0	0	43	1 411
QC	95	384	1 933	1 076	24	0	81	3 593
ON	355	324	1 058	3 810	18	0	122	5 687
MB	0	427	945	0	0	0	138	1 510
SK	0	2 043	510	1 465	0	634	284	4 936
AB	191	3 876	1 679	1 788	2 001	1 212	611	11 358
BC	0	525	1 787	414	0	0	176	2 902
YT	0	0	3	0	0	0	9	12
NT	0	232	141	0	0	0	26	399
NU	0	0	114	0	0	0	0	114
Total	641	7 956	11 562	9 628	2 043	1 846	1 611	35 287

Objective

The objectives of the Regulations are to

• Reduce fugitive VOC releases from petroleum liquid storage tanks and loading equipment in Canada;
• Protect human health by minimizing, to the greatest extent practicable, exposure to carcinogenic VOCs such as benzene;
• Improve human health and environmental quality by reducing smog formation;
• Promote a level playing field through nationally consistent VOC risk management measures;
• Harmonize these measures, to the extent possible, with existing measures in other jurisdictions (e.g. provinces, municipalities and the United States); and
• Provide regulatory certainty, which would allow facility owners to make informed long-term investment decisions and build confidence among other interested parties that environmental and health outcomes will be achieved.

Description

The Regulations establish equipment-based requirements^{footnote 22} for new and existing volatile petroleum liquid^{footnote 23} storage tanks and loading operations at petroleum and petrochemical facilities (hereinafter referred to as “regulated facilities”) located in Canada. Applicability is facility-specific, and the operator of each regulated facility (hereinafter referred to as “operator”) is required to

• Install emissions control equipment on storage tanks and loading equipment;
• Implement an inspection and repair process; and
• Undertake record-keeping and reporting activities.

The Regulations define criteria for the time permitted for regulated facilities to bring equipment into compliance and these criteria are based on the equipment’s prior condition and emissions risk. The implementation of the Regulations will follow a phased-in approach, requiring regulated facilities to prioritize highest-emitting equipment. See the Coming into force subsection for further details.

Sampling and testing

The Regulations require the use of specific ASTM International (formerly known as the American Society for Testing and Materials) or Canadian General Standards Board standard methods (incorporated by reference) whenever sampling and testing liquids to determine VOC concentration, vapour pressure, or benzene content. A permitting system enables the Minister to approve alternatives to these standard methods in cases:

• where the specified methods are not applicable to the liquid being tested;
• where an operator has identified a method that produces more accurate or precise results; or
• where an operator wishes to use automated sampling or testing but automation is not supported by the specified methods.

The Regulations require that instruments meet design and performance requirements when they are used to perform inspections, such as leak testing of vapour control systems, or lower explosive limit testing of internal floating roof tanks.

Emissions control equipment

Regulated facilities are required to install, maintain and repair emissions control equipment on storage tanks and loading racks that handle volatile petroleum liquids, as described in Table 3.

In addition, regulated facilities are required to follow the standard CAN/CGSB-3.1000-2024, Vapour Control Systems in Gasoline Distribution Networks, when loading gasoline to or from trucks. This national standard is voluntarily followed by most facilities in Canada that already use vapour control systems while loading gasoline.

Table 3: Proposed emissions control equipment requirements and exemptions

Type of installation	Requirement
Large tanks (greater than 150 m3 internal volume)	Internal floating roof, external floating roof or vapour control system
Small tanks (between 50 m3 and 150 m3 internal volume, or between 5 m3 and 150 m3 internal volume if storing gasoline)	Pressure-vacuum vent
High emissions risk tanks (storing high benzene liquids table e3 note a or high vapour pressure liquids (exceeding 76 kilopascals (kPa) vapour pressure))	Vapour control system table e3 note b
Tanks with internal volumes less than 50 m3 not storing gasoline, high benzene liquids or high vapour pressure liquids (exceeding 76 kPa vapour pressure) All tanks less than 5 m3	Exempt - no requirements
Loading racks	Vapour control system Vapour balancing system permitted at bulk plants
Low-throughput table e3 note c or remote table e3 note d loading racks	Exempt - no requirements
Table e3 note(s) Table e3 note a Throughout this document, "high benzene liquid" means a volatile petroleum liquid with a benzene concentration greater than 20% by weight, and "high benzene tank" means a tank that may contain a high benzene liquid. Return to table e3 note a referrer Table e3 note b The use of floating roofs for some existing high benzene tanks will be permitted where fenceline monitoring establishes exposure risks are low, and there is a distance of more than 300 m to the nearest occupied building. Return to table e3 note b referrer Table e3 note c A loading rack qualifies as low throughput if the throughput is below a calculated threshold. This threshold is dependent on liquid vapour pressure, benzene content, the type of vehicle being loaded, and the distance of the loading rack from off site buildings, but it is equivalent to 25 million standard litres of gasoline per year loaded to truck if the distance to off site buildings is at least 300 m, or 1 million standard litres of gasoline per year with no minimum distance. Return to table e3 note c referrer Table e3 note d A loading rack qualifies as remote if it loads liquids with a benzene concentration less than 0.5% by weight and a vapour pressure less than 76 kPa, and it is located more than 1 500 m from off site buildings and more than 50 km from the nearest population centre with more than 20 000 inhabitants. Return to table e3 note d referrer

The Regulations also set out a permitting system that allows the Minister to approve the use of alternative emissions control equipment in cases where the operator can demonstrate its efficacy.

Inspections and repairs

Operators are required to inspect the emissions control equipment and undertake repairs where necessary, including

• Monthly visual inspection of external floating roof tanks for major defects or flooding;
• Monthly lower explosive limit testing of internal floating roof tanks;
• Annual measurement of the secondary rim seal gaps of external floating roof tanks. Primary rim seal gap measurements are required every five years;
• Internal inspection of internal floating roof tanks, including rim seals, every twenty years;
• Annual inspection of pressure-vacuum vents;
• Maintaining a continuous monitoring system on vapour recovery or destruction systems;
• Monthly inspection of vapour control systems for leaks; and
• Testing of vapour recovery or destruction system performance every five years.

Operators are required to repair defects in emissions control equipment within timelines set out in the Regulations, starting from the date when the defect was discovered. The timeline for floating roof tank repairs is within 60 days, or up to 180 days if a temporary vapour control system is used,^{footnote 24} while the timeline for vapour control system repairs is within 45 days. A shorter repair timeline is required for higher emission risk events where floating roofs have sunk or lower explosive limit testing results are very high. Repair timelines do not apply during periods of time where the equipment requiring repair has been temporarily removed from service, such as when a tank has been emptied and cleaned.

Extended timelines are permitted under specified circumstances, including cases where there are problems emptying or cleaning tanks to prepare for repair, or where there is a risk of significant disruption of operations. Interim emission mitigation measures are required for tanks and loading racks used for high benzene liquids, and development and implementation of an emissions minimization plan is required whenever cleaning the interior of a tank or replacing the rim seal of an internal or external floating roof tank.

Record-keeping and reporting

Operators are required to

• Keep records of inspections, maintenance, measurements, equipment specifications and personnel training;
• Retain the records for six years, except for records relating to the design or construction of equipment, which must be retained for the lifespan of the equipment, and records relating to inspections performed at intervals longer than six years, which must be retained until the date of the next inspection;
• Register regulated facilities with the Department;
• Submit reports in the event of major tank emissions control failures, namely if a floating roof has sunk or lower explosive limit testing results are very high; and
• Submit reports containing fenceline monitoring data if the facility is using floating roofs instead of vapour control systems to control emissions from existing high benzene tanks.

Scope of coverage

The Regulations apply to facilities that

• Store more than 500 m³ of volatile petroleum liquids;
• Load and unload more than four million standard litres of volatile petroleum liquids per year;
• Store volatile petroleum liquids with a benzene concentration equal to or greater than 20% in tanks that are 5 m³ or larger; or
• Store volatile petroleum liquids with a vapour pressure equal to or greater than 76 kPa in tanks that are 100 m³ or larger.

A substance is considered to be a volatile petroleum liquid if it is a hydrocarbon derived from petroleum or coal that is liquid at standard conditions (20 °C, 101.325 kPa) and has a vapour pressure exceeding 10 kPa, or exceeding 3.5 kPa if it also contains greater than 2% benzene by weight^{footnote 25}. By this definition, gasoline, most crude oils, some intermediate products and some petrochemicals are in scope, while liquids with low VOC emissions such as diesel fuel, kerosene type jet fuel, heating oil and some heavy crudes are not in scope. Ethanol-petroleum mixtures containing less than 10% by weight of petroleum are also excluded from scope.

Exemptions for facilities and equipment with low emission risks include

• Facilities exclusively engaged in retail fuel sales;
• Tanks and loading racks covered by the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector);
• Upstream oil and gas facilities where emissions are generally addressed by the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) or equivalent provincial requirements, specifically facilities engaged in:
• Extraction;
• Primary processing;
• Storage upstream of primary processing facilities;
• Gas processing;
• Offshore facilities located more than 3 nautical miles from shore; and
• Small facilities (primarily terminals and bulk plants) which meet the criteria noted in Table 4.

Table 4: Criteria for additional exempted facilities
Facilities handling liquids with greater than 2% benzene content by weight do not qualify for any of these exemptions. Facilities handling liquids with vapour pressure greater than 76 kPa do not qualify for the distance to offsite occupied building exemptions.

Criteria	Maximum onsite storage capacity table e4 note a (m3)	Maximum annual loading/unloading table e4 note b (m3/year)	Maximum daily loading/unloading table e4 note b (m3/day)
Distance to offsite occupied building – more than 60 m Tank size - facility only stores volatile petroleum liquids in fixed roof tanks less than 150 m3 internal volume, or in underground tanks	2 000	20 000	500
Distance to offsite occupied building - more than 300 m	2 000	25 000	500
Distance to urban areas – more than 100 km from any population centre with more than 20 000 inhabitants	10 000	30 000	2 000
Table e4 note(s) Table e4 note a Storage capacity is the total internal volume of all tanks used to store volatile petroleum liquids Return to table e4 note a referrer Table e4 note b Includes loading to vehicle tanks (e.g. trucks) and unloading to fixed roof tanks Return to table e4 note b referrer

Coming into force

The Regulations come into force upon registration, but allow for the delayed application of certain provisions. Regulated facilities are required to ensure that new storage tanks and loading racks (those that enter service after the registration of the Regulations) comply with all requirements at the time they are first used to store or load petroleum liquids.

Regulated facilities are required to bring a certain percentage of existing storage tanks and loading racks into compliance each year. A period of one to three years is permitted to bring equipment into compliance, depending on its prior condition and emissions risk. High benzene tanks are subject to shorter implementation timelines – within one year for the highest-risk tanks. At least 80% of tanks at a facility would need to be in compliance within the first three years, and each subsequent year the percentage of non-compliant tanks would need to be reduced by 5%. If an existing floating roof tank does not fully meet the design requirements, but it continues to meet the performance requirements of the regulations, upgrades may be postponed until it fails an in-service inspection or when it comes out of service for an inspection.

In cases where a facility has more than two tanks that require emissions control equipment, a period of between four and seven years total is allowed for tanks, provided that at least 80% of the tanks meet the requirements of the Regulations after three years. Up to five years total for loading racks is allowed for facilities that have two or more loading racks to be equipped with emissions control equipment, or if the facility has a small throughput (equivalent to less than 175 000 m³ of gasoline). Regulated facilities are required to submit an implementation plan to the Department and confirm when the facility is in compliance with the Regulations.

Based on this phased-in approach, most high-emitting loading racks will be fitted with emissions control systems between 2026 and 2028 and most tanks, including all tanks posing the highest benzene emissions risks, will be brought into compliance by the end of 2028. The remaining equipment will be brought into compliance at a rate of over 14% each year until 2032, when all equipment would need to be in compliance. See Table 5 for a summary of the compliance timelines.

Table 5: Timeline for compliance with the Regulations

Timeline	Items to comply with Regulations	Compliance flexibility
Upon registration	Emissions controls for new tanks and loading racks Inspections and repairs of new tanks and loading racks	N/A
One year after registration	Emissions controls for tanks storing liquids with >20% benzene content Emissions controls for loading racks loading liquids with >20% benzene content	Facilities with at least three high benzene tanks not meeting the requirements of the Regulations must bring two into compliance in the first year. Up to one additional year is allowed to bring the remaining tanks into compliance.
	Inspections and repairs of existing tanks and loading racks Design, operation, and performance requirements for existing vapour control systems and floating roofs Record-keeping and reporting requirements	Existing vapour control systems used for high benzene tanks and loading racks must comply with the general performance specification at this time, then have an additional year to comply with the stricter, benzene-specific performance standard.
Three years after registration	Emissions controls for at least 80% of existing tanks at the facility, or all existing tanks if two or fewer required installation of new emissions control equipment	Up to four additional years to bring remaining existing tanks into compliance at a rate of 5% of the facility’s total tanks per year
Three years after registration	Emissions controls for higher emitting loading racks	Up to one additional year to bring marine loading racks into compliance Up to two additional years to bring remaining lower emitting loading racks into compliance
Ten years after registration	Internal inspections of existing internal floating roof tanks with previous inspections more than ten years before registration	N/A

Regulatory development

Consultation

Initial consultations

Initial consultations began in May 2021 with the release of a discussion document entitled A proposed approach to control volatile organic compounds (VOC) emissions from the storage and loading of petroleum liquids (the Proposed Approach). At that time, the Department contacted industry representatives, provincial, territorial and municipal governments, Indigenous groups and NGOs to notify them of the publication of the Proposed Approach and to seek input. A 60-day informal comment period was initiated, ending in July 2021.

In the weeks following the release of the discussion document, the Department conducted webinars providing more detail on the Proposed Approach; the webinars were attended by a total of 250 participants. It also held meetings with several organizations to discuss their questions and concerns. The Department received 30 written submissions from industry organizations, individual companies, provincial, territorial and municipal governments and Indigenous groups. No written comments were received from either NGOs or private individuals.

The Department continued to engage with interested parties until fall 2023, holding meetings and telephone calls and exchanging email correspondence, as well as visiting refinery, terminal, and chemical plants and community sites.

Input received during these consultations helped inform the proposed Reduction in the Release of Volatile Organic Compounds (Storage and Loading of Volatile Petroleum Liquids) Regulations (the Proposed Regulations).

Consultations on the Proposed Regulations – February to October 2024

The Proposed Regulations, along with a Regulatory Impact Analysis Statement describing the initial consultations, were published in the Canada Gazette, Part I, on February 24, 2024. This was followed by a 60-day consultation period.

During the development and implementation of the Interim Order, additional consultation took place with the Aamjiwnaang First Nation, provincial authorities and industry, which further informed the development of the Regulations. The Department has considered the input received during the 60-day public comment period, and continued to meet with Indigenous peoples, provincial and municipal governments and industry until late 2024. Following the publication of the Proposed Regulations, the Department held over 70 bilateral meetings, contacted 460 organizations and held webinars with 243 participants. The Department received 50 written submissions, including technical information from major petroleum and petrochemical companies.

In general, industry, provinces and Indigenous peoples were satisfied with how their feedback on the Proposed Approach was reflected in the Proposed Regulations. As a result, many of the comments on the Proposed Regulations focused on technical details as opposed to philosophical differences in approach, rationale or framework.

Provincial and municipal governments were mostly supportive of or neutral about the Regulations, and comments from these jurisdictions included suggestions for more stringent measures, information sharing requests, and questions about managing potential overlap between federal and local requirements. Feedback from Indigenous peoples, industry, NGOs, consultants and technology providers focused on specific aspects of the proposal and sought changes to certain requirements and some applicability criteria. Members of the general public who submitted comments on the Proposed Regulations were generally supportive.

Industry

Industry has been generally supportive of the proposed regulatory approach. The Department engaged in over 60 meetings with industry representatives from the oil and gas sector, the chemicals sector and other industrial sectors, such as the steel and transportation sectors, that could be affected by the Regulations. Key interested parties involved in these discussions were the Canadian Fuels Association, the Canadian Association of Petroleum Producers, the Canadian Trucking Alliance, the Chemistry Industry Association of Canada, the Canadian Steel Producers Association, Energy Connections Canada and individual companies operating oil and gas or chemical facilities in Canada. These representatives were supportive of the health and environmental objectives of the approach as well as the overall structure proposed (requirements for the use of emissions control equipment combined with requirements for inspection and repair) but suggested some technical amendments to the Regulations.

Provincial, territorial and municipal governments

Most government representatives who participated in the information sessions and bilateral meetings indicated support, while some were neutral regarding the Regulations.

All provinces and territories were informed of the Regulations, and some jurisdictions (Alberta, Newfoundland and Labrador, Northwest Territories, Nova Scotia, Ontario, Saskatchewan, City of Montréal) provided written comments, while others (Quebec, Metro Vancouver) also engaged in information sessions or discussions with the Department.

As discussed above, some strongly supported the Regulations and asked for additional reporting for higher-risk activities, some appreciated the exemptions for small and remote facilities, a few questioned if a federal approach was necessary given the existing measures in place in certain jurisdictions, and others expressed a desire for involvement or notifications regarding enforcement, data sharing, and interaction with any requirements already in place in their respective jurisdictions.

Indigenous partners

The Aamjiwnaang First Nation provided written comments and met directly with the Department regarding the Regulations as well as the Interim Order. Comments were generally supportive of the Regulations, appreciating the Department’s recognition of emissions impacts on the Aamjiwnaang First Nation. As noted above, one of the comments urged for immediate action to reduce benzene emissions impacting the community and led to the publication of the Interim Order.

Additional comments were specific to seeking greater involvement in implementation and enforcement, access to regulatory data, and accelerated delivery and implementation timelines.

Additional information on Indigenous consultation is included in the “Modern treaty obligations and Indigenous engagement and consultation” section.

Non-governmental organizations

Comments from environmental non-governmental organizations (Canadian Environmental Law Association, Ecojustice, Environmental Defence Canada, Pembina Institute) stressed the importance of proceeding with stringent regulations that would come into force as quickly as possible, to protect the health of Canadians and the environment. Some groups also advocated for consideration of worker exposure and risk-based inspection approaches, as well as some clarifications in the Regulatory Impact Analysis Statement.

A summary of the key areas identified in the comments from industry, provincial, territorial and municipal governments, Indigenous partners and non-governmental organizations and how the Department responded to those comments are described in the subsections below.

Immediate action to reduce benzene emissions impacting Aamjiwnaang First Nation

Comments from Indigenous partners, including the Aamjiwnaang First Nation, advocated for accelerated delivery of the Regulations to urgently address benzene emissions from storage tanks affecting the Aamjiwnaang First Nation.

In response to these comments, the Minister made the Interim Order in May 2024 to address an urgent and significant danger to human health posed by benzene emissions from petrochemical facilities in Sarnia. The technical requirements imposed by the Interim Order were designed to have a similar effect to those in the Regulations but took effect much earlier to address the need for immediate action. The Interim Order ceases to have effect when the Regulations are made. The Regulations were updated to ensure seamless coverage of facilities and equipment that were subject to the Interim Order.

Timing of requirements coming into force

Comments from Indigenous partners, including the Aamjiwnaang First Nation, advocated for accelerated delivery and implementation timelines of the Regulations. Comments from environmental NGOs stressed the importance of proceeding with stringent regulations that would come into force as quickly as possible, to protect the health of people in Canada and the environment.

Industry representatives expressed concerns with the proposed implementation timelines for high benzene tanks, citing logistical challenges with fitting emissions control equipment, procurement and supply considerations, as well as timing to obtain permits from local jurisdictions. Most companies impacted by the one-year timeline for high benzene tanks have highlighted challenges that they will face in meeting the timeline but have also given an indication that engineering analysis is underway to develop a pathway to compliance.

In response to these comments, the one-year timeline for implementation of emissions controls on the highest-risk tanks and loading racks has been maintained. To address industry concerns about the challenges of retrofitting multiple high benzene tanks within a one-year period, the Regulations now require at least two high benzene tanks to be addressed within one year, and two more high benzene tanks to be addressed every subsequent year until the facility meets all the requirements of the Regulations. This flexibility will ensure reductions in the highest-risk benzene emissions as soon as possible and within the timelines deemed safe and operationally feasible based on the Department’s experience from implementing the Interim Order.

Some industry representatives stated permitting for work on marine docks could make meeting the proposed three-year timeline to install vapour controls at marine terminals challenging. Some Indigenous partners supported the one-year timelines to equip loading racks with vapour controls if benzene emissions are of particular concern. In response to these comments, the one-year timing for loading racks that handle high benzene content liquid to be equipped with vapour control systems has been maintained. Additionally, the timing for marine terminals to be equipped with vapour control systems was adjusted to four years instead of three years, provided that the marine terminal does not load high benzene content liquids. This recognizes the longer project timelines associated with marine terminals, without compromising on the one-year timeline for high benzene content liquids.

Applicability criteria to small facilities

Industry representatives commented that many small facilities that they expected to be exempt from the Regulations, did not qualify for the exemption criteria specified in the Proposed Regulations and therefore a large number of small facilities would end up being subject to the Regulations if the exemptions were not adjusted. Additionally, territorial governments and Indigenous representatives from northern areas indicated a need for considerations to ensure that the Regulations would not disrupt the community fuel supplies in northern areas, citing fragile supply chains and extreme weather conditions.

After reviewing these comments, the Department requested additional data from industry representatives regarding their bulk plant operations. New facility-specific data for bulk plants was provided to the Department by some industry representatives. The analysis of this new data for bulk plants allowed the Department to draw two specific conclusions: (1) Additional exemption criteria could be added to the Regulations while still meeting the risk management objectives, and (2) More bulk plants would be in scope of the Regulations than was previously estimated.

The exemption criteria from the Proposed Regulations only allowed for very small bulk plants to be exempt if they were located less than 300 metres from offsite occupied buildings. The Department analyzed the new dataset provided by industry representatives and concluded that additional exemption criteria should be included in the Regulations to best align with the regulatory intent and risk management objectives. This analysis included a review of benzene exposure using a similar approach to the approach used in the Government of Canada’s Screening Assessment – Petroleum Sector Stream Approach: Natural Gas Condensates.

Based on the limited facility-specific data that was available for analysis during the development of the Proposed Regulations, it had been assumed that many bulk plants would have a minimum distance of 300 m between tanks or loading racks and offsite occupied buildings. However, the dataset provided by industry representatives indicated most bulk plants would not meet this criterion.

To directly respond to these findings, additional exemption criteria have been included in the Regulations to avoid unnecessary cost for small and medium-sized bulk plants with a minimum distance of 60 m from offsite occupied buildings, as well as for very small bulk plants regardless of setback distance, but the dataset also indicated that the number of bulk plants in scope of the Regulations is higher than was previously estimated. The impact analysis for the Regulations has been updated with new exemption criteria and a more accurate number of bulk plants estimated to be covered by the Regulations. This means the number of bulk plants estimated to be covered by the Regulations, detailed in Table 1, is higher than the estimate provided in the Canada Gazette, Part I publication in February 2024.

Overall, the additional 164 bulk plants accounted for in the regulatory analysis has increased the total reduction in VOC emissions by approximately 5% and increased the total estimated cost of the Regulations by less than 6%. This change is based on additional data submitted by industry representatives, which allowed the Department to perform more detailed analysis and emissions modelling. This change avoids imposing unnecessary costs on small low-risk facilities while ensuring risk management objectives are met.

Vapour pressure testing methods

Industry representatives sought changes to the testing method for vapour pressure to better align with current industry practices and to permit most crude oil storage tanks to continue using their existing floating roofs as appropriate emission controls. In the Proposed Regulations, the vapour pressure testing methods would have required many crude storage tanks to be retrofitted with a fully sealed vapour control system instead of a floating roof to control emissions. Industry was concerned this would lead to excessive costs with minor improvements to emission reductions.

The Department requested additional data from industry representatives to investigate these comments in more detail. The data submitted by industry representatives allowed the Department to review the impact of different testing methodologies and validate the need for the change in testing method.

In response to these findings, the testing method of vapour pressure set out in the Regulations has been adjusted to align with current industry practices. This change avoids imposing unintentionally strict requirements on crude oil tanks. With the change in testing method, most crude oils will be below the “high volatility” threshold, as originally intended by the Department, allowing them to continue to use tanks with floating roofs, rather than requiring a fully sealed vapour control system.

Inspection frequencies

Industry representatives sought changes to proposed inspection requirements for storage tanks, such as reduced frequency of visual inspection of internal floating roof tanks, longer intervals for out-of-service tank inspections and less stringent testing conditions for vapour space inspections of internal floating roof tanks. Some provincial and municipal governments advocated for alignment of performance testing of vapour control systems with existing rules in some jurisdictions, such as in Montréal. Additionally, some NGOs advocated for consideration of worker exposure and risk-based inspection approaches to reduce cost and burden on industry while optimizing the efficiency and effectiveness of inspections. Some Indigenous partners supported the Department’s proposal of frequent inspections of floating roof tanks and vapour control systems for leaks.

In response to these comments, the Regulations maintain a similar frequency of inspection of the vapour space of internal floating roof storage tanks but the stringency of the meteorological and operational conditions for inspections was reduced (by adding flexibility for tanks with continual flow of liquid, by removing certain control conditions related to the liquid level in the tank, and by allowing additional inspections to be omitted if weather conditions cause safety concerns or access problems). The Regulations were also adjusted to remove the requirement to take external floating roof tanks out of service to conduct inspections and to remove the requirement for monthly visual inspections of internal floating roof storage tanks.

The rationale for these changes is that emissions control performance can be effectively assessed using less invasive inspection techniques. The use of an instrument to measure the lower explosive limit of the vapour space of internal floating roof tanks is more effective and reduces worker exposure compared to monthly visual inspections. Regarding external floating roof tanks, many facilities perform appropriate inspections of external floating roof seals without removing the tank from service. In addition to reducing costs associated with degassing and cleaning tanks, this change will also reduce emissions associated with degassing tanks.

The Department also considered risk-based inspection approaches for storage tanks and the Regulations will allow storage tank floating roof seals to be inspected without requiring the tank to come out of service. This will reduce the costs of maintenance and inspection of storage tanks and reduce emissions associated with tank degassing.

Repair timelines

Industry representatives requested that timelines for repair work be extended when work is delayed by unavoidable circumstances, including federal, provincial or municipal regulatory approvals. Industry representatives highlighted recent challenges with obtaining jurisdictional approvals on the use of vapour combustion equipment.

In response to these comments, additional wording was added to the Regulations to allow for an extension of timelines if work was delayed due to the need to obtain permits from federal, provincial or municipal regulators.

Use of alternative vapour control systems

Industry representatives advocated for a broader definition of vapour control systems, and multiple companies submitted data to support the continued use of existing vapour control systems in place at many facilities.

In response to these comments, the Regulations allow a broader range of emissions control technologies such as boilers and incinerators to be used, while ensuring that performance criteria are met.

This change was informed by technical data shared by industry representatives. It ensures that existing emissions control equipment can continue to be used in cases where it is functioning well.

Clarity on applicability to upstream oil and gas facilities

Industry representatives also raised concerns about the possibility of requirements overlapping or conflicting with other regulated requirements, including provincial regulations and initiatives to reduce methane emissions from the upstream oil and gas sector.

In response to these comments, the applicability section of the Regulations pertaining to the upstream oil and gas sector has been clarified. The Regulations also explicitly exempt equipment if it is covered by the Regulations Amending the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector).

The intention for coverage remains unchanged from the Proposed Regulations, but the changes provide more clarity based on feedback from industry representatives.

Questions of conflict between a federal regulation and existing measures in place in certain Canadian jurisdictions

Industry representatives also raised concerns about the possibility of requirements overlapping or conflicting with other regulated requirements, including provincial regulations and initiatives to reduce methane emissions from the upstream oil and gas sector. In particular, industry representatives noted that the requirements for measuring vapour control system performance in the Proposed Regulations differed from existing practices, including regulated requirements in some jurisdictions.

A number of provincial, territorial and municipal government representatives who participated in the information sessions questioned whether there was any conflict between the Regulations and existing provincial or municipal rules for these facilities. Provincial government representatives asked for additional reporting for higher-risk activities.

In response to these comments, the interval between performance testing of vapour control systems has been extended from a one-year interval to a five-year interval. This would avoid unnecessary burden on facilities who are also required to perform testing under provincial or municipal rules. The Regulations have a strong focus on continuous emissions monitoring, which means the longer performance testing interval is not anticipated to impact the effectiveness of the Regulations. The Regulations have been adjusted to ensure it is clear that vapour control systems would be verified over an hourly average rather than instantaneously, aligning with existing practices in other jurisdictions. Additional reporting and notification requirements for activities involving high benzene tanks have also been added to the Regulations.

Desire for involvement in implementation of the Regulations

Representatives from some provincial and municipal governments, as well as some Indigenous partners, requested the Department share more information regarding notifications of enforcement, data sharing, and for additional reporting for higher-risk activities.

In response to these comments, the Regulations now include notification requirements for cleaning high benzene tanks. Additionally, the Department is also assessing ways, outside of changes to the regulatory approach, to work together with local jurisdictions on information sharing, notifications and compliance assurance activities. This would also involve other similar regulations such as the existing Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector).

The Department has also engaged in additional discussions with the Aamjiwnaang First Nation regarding the Regulations and continues to assess ways to work together on information sharing, notifications and compliance assurance activities.

Modern treaty obligations and Indigenous engagement and consultation

Modern treaty obligations

As required by the Cabinet Directive on the Federal Approach to Modern Treaty Implementation, an assessment of modern treaty implications was conducted on the regulatory proposal. This assessment included an examination of the geographical scope and subject matter of the initiative in relation to modern treaties in effect. The geographical scope of the Regulations includes all locations in Canada where regulated facilities are found, including parts of all provinces and territories.

During the development of the Proposed Regulations, potential modern treaty implications were identified for four fuel distribution facilities located in northern Quebec and covered under the James Bay and Northern Quebec Agreement (JBNQA). However, following the publication of the Proposed Regulations, the Department conducted further analysis and concluded that the four facilities identified under the JBNQA are below the storage and loading limits and are excluded from the requirements of the Regulations.

Indigenous engagement and consultation

The Department engaged a number of Indigenous groups during the development of the Regulations. Groups who either submitted written comments or pursued bilateral discussions following the publication of the discussion document in 2021 included the Inuit Tapiriit Kanatami, the Tsleil-Waututh Nation, the Fort McKay First Nation, the Fort McKay Métis Nation and the Aamjiwnaang First Nation. Indigenous representatives were supportive of the environmental objective of the draft approach, but raised concerns related to local air quality, enforcement and record-keeping, and possible effects to fuel supply in northern areas.

Representatives from communities affected by high ambient levels of benzene and other VOCs sought measures to ensure that the Regulations would effectively mitigate these issues, in particular the use of the best available control and monitoring technology on equipment with a high potential for benzene emissions; comprehensive coverage of sources, including wastewater treatment, sewers, and other sources; rapid implementation of requirements; and transparent, publicly available record-keeping and reporting. There was also a desire for increased involvement in the regulatory development and enforcement process. The Aamjiwnaang First Nation noted that air quality and ambient levels of benzene near their community continue to be among the worst relative to many other industrialized areas in North America, and that feasible and effective air pollution control solutions are available but have not been implemented. The Fort McKay First Nation and the Fort McKay Métis Nation noted the importance of addressing fugitive emissions of VOCs from oil sands facilities such as upgraders which impact the Nations’ quality of life and enjoyment of their traditional territories.

Representatives from northern areas indicated a need for considerations to ensure that the Regulations would not disrupt the community fuel supplies in northern areas, citing fragile supply chains and extreme weather conditions.

In response to concerns related to benzene and VOC exposure, the implementation timelines have been accelerated to ensure that requirements affecting sources with a high potential for benzene emissions come into effect as soon as possible. The permissible amount of benzene in vapour control system exhaust has also been lowered. In response to concerns related to record-keeping and reporting, the Regulations now include additional reporting and record-keeping requirements for equipment inventories, repairs and implementation progress, and the Department will evaluate options for making reported data publicly available, while protecting confidential business information. Furthermore, the Department will continue to analyze information, including monitoring data, on additional emission sources not addressed by the Regulations, such as wastewater treatment and sewers, to evaluate the risks associated with these sources and determine whether controls are warranted.

In response to concerns related to fuel supply in northern areas, the Department included provisions to prevent application of the Regulations to small facilities in remote areas, and included allowances for longer repair timelines when conditions make it difficult to complete repairs quickly.

As required by the United Nations Declaration on the Rights of Indigenous Peoples Act, a UN Declaration Consistency Analysis was completed for the Regulations. It is expected that the Regulations will contribute to the implementation of the UN Declaration as they will result in improved air quality and human health for the Aamjiwnaang First Nation and other Indigenous communities; resulted from a process aimed at obtaining free, prior and informed consent; responded to the particular needs and lived experience of Aamjiwnaang First Nation and other Indigenous communities; took into account Indigenous perspectives; and aimed to protect the environment further to those perspectives.

Instrument choice

The Department reviewed and assessed various regulatory and non-regulatory instruments to determine the best instrument to achieve the objectives of the Regulations. The assessment was based on a variety of criteria, such as environmental effectiveness, economic efficiency, distributional impact, enforceability and feasibility of implementation, interested party and partner feedback and jurisdictional compatibility. A summary of conclusions is presented below.

Baseline scenario

As indicated above in the “Existing risk management measures in Canada” section, some regulated facilities have vapour control measures installed for loading racks, while some have vapour control measures installed on storage tanks. Many of these vapour control measures were developed based on two voluntary CCME instruments published in 1991 and 1995. These voluntary instruments focus on ground-level ozone impacts from VOCs, without giving specific consideration to health impacts from carcinogenic VOCs such as benzene.

The CCME guidelines for storage tanks only require inspection of internal floating roof tanks every 10 years or alternative annual lower explosive limit testing. If only minimal guidelines are followed, large leaks could continue for a long period of time before they are detected and repaired. Timely detection and repair of small and large leaks are critical because even short-term exposure to low concentrations of the carcinogenic emissions can cause harm to human health. Recent air emissions monitoring has shown high ambient levels of benzene near some large storage tanks, despite the tanks being equipped with vapour control measures described in the CCME guidelines, suggesting potential gaps in the guidelines’ equipment specifications and/or inspection and maintenance criteria.

The CCME Code for loading racks focuses on gasoline loading to trucks, without covering gasoline loading to rail or marine, and without covering other volatile petroleum liquids, including those that can contain carcinogenic substances. The Department estimates that over half of all medium and large throughput loading racks are currently uncontrolled.

Given these limited control measures, maintaining the status quo is not the preferred option because it does not effectively address the risks presented by VOCs for people in the vicinity of facilities that are emission sources.

Code of practice

A code of practice would provide technical specifications in a standardized document that identifies and promotes the best practices to reduce emissions from storage tanks and loading racks. A code of practice would not be expected to further reduce VOC releases, as respecting it would be voluntary rather than enforceable. It is expected that not all facilities would adopt a code of practice if it were to be developed, as evidence shows that some facilities do not follow the existing CCME Code and Guidelines (numerous facilities do not currently use vapour control for loading racks). Therefore, a code of practice was not considered as a viable instrument as it would not result in the reductions of VOC releases that are necessary to adequately protect human health.

Pollution prevention planning notice

A pollution prevention (P2) planning notice is a flexible instrument that can be used to manage risks to the environment and human health and that could minimize the need for additional regulatory intervention. Persons subject to a P2 planning notice must prepare and implement a P2 plan that meets the requirements of the notice, must have their plan available on site, and must carry out the actions identified in their plan. The implementation of P2 plans is enforceable; however, their contents can vary because each facility develops its own P2 plan. A P2 planning notice would therefore not foster national consistency. Further, a P2 planning notice would not guarantee the implementation of measures that are needed to minimize exposure to carcinogenic components present in volatile petroleum liquids to the greatest extent practicable, such as frequent inspections (e.g. monthly inspections of internal floating roof tanks) and installation of high-performance vapour control systems. Consequently, the Department concluded that a P2 planning notice was not the best instrument to achieve the objectives of the Regulations.

Market-based instruments

The Department considered market-based instruments such as cap-and-trade programs, as well as fees and charges.

A cap-and-trade system would put a ceiling on the sector’s VOC emissions and allow facilities to earn and exchange credits. Recent assessments of benzene indicate that a high priority should be placed on options to reduce exposure for those in the vicinity of industrial sources. Prescribing the locations where the emission reductions should occur would not be possible through a cap-and-trade system; the locations would be determined by the markets. Therefore, the objective of protecting people in the vicinity of the regulated facilities in Canada cannot be achieved through the cap-and-trade system.

Alternatively, fees and charges could be levied on facilities that emit VOCs above an established threshold. This approach would require a significant amount of administration on the part of the regulated parties and administration and monitoring by the regulator, as well as significant time required to configure fees and charges that would achieve the emission reductions in the most affected local and regional areas.

Furthermore, revising the fee structure as technology evolves would be costly and time-consuming, and would fail to take advantage of the existing equipment-based regulations in some Canadian jurisdictions. This approach would be lacking in enforceability in addressing local air quality issues.

Neither of these two instruments (cap and trade, or fees and charges) were considered to be acceptable instruments for the reasons stated above. Either approach would also suggest that there is an acceptable amount of releases of carcinogens (for trade, or above which fees and charges would be levied), which is not the case.

Amending existing regulations

There are existing federal regulations that address petroleum storage tanks, namely the Storage Tank Regulations, to reduce liquid leaks and spills from storage tank systems. The Storage Tank Regulations, last amended in 2020, apply only to tanks located on federal or Aboriginal land, or operated by specified agencies under federal jurisdiction. There is minimal overlap between the Storage Tank Regulations and the Regulations in terms of regulated parties, or in terms of requirements other than basic record-keeping and facility registration. Therefore, an extensive amendment of the Storage Tank Regulations, instead of establishing new regulations, was also rejected as an option.

New regulations

New national regulatory requirements were considered to be the most practical and effective way to reduce evaporative VOC releases and thereby reduce exposure to carcinogenic components and protect human health. New regulations would provide specific requirements that ensure local air quality issues would be addressed, while ensuring enforceability and providing certainty and general alignment with regulations already in place in other jurisdictions. Being mandatory and uniform, regulatory measures would provide consistent VOC emissions control systems across regulated facilities in the Canadian petroleum and petrochemical sectors, thereby achieving the objectives of the Regulations.

Regulatory analysis

Benefits and costs

Analytical framework

The benefits and costs associated with the Regulations were assessed in accordance with the Treasury Board Secretariat of Canada’s Cost-Benefit Analysis Guide for Regulatory Proposals, which includes identifying, quantifying and, where possible, monetizing the impacts associated with the policy. A cost-benefit analysis was conducted to assess the incremental impacts of the Regulations by comparing two scenarios. The baseline scenario assumes that regulated facilities would continue to meet existing regulatory requirements or continue voluntary practices for controlling fugitive VOC releases. The regulatory scenario assumes that regulated facilities would take the actions required by the Regulations. The differences in impact between the regulatory scenario and the baseline scenario are the incremental impacts (costs and benefits) of the Regulations. Incremental costs were quantified and monetized. Incremental benefits were quantified and monetized wherever possible; otherwise, they were described qualitatively.

The Regulations come into force in 2025 and provide up to seven years for regulated facilities to achieve compliance (e.g. larger facilities, which have more storage tanks, are provided with more time to bring all of their tanks into compliance). The analytical time frame is 21 years, which begins in 2025 (the year the Regulations are expected to come into force) and ends in 2045. This time frame was selected to capture multiple cycles of some costs that occur every 10 years, and to align generally with the expected service life of the emissions control equipment. Unless otherwise indicated, all values are presented in 2022 Canadian dollars, discounted at 2% to the year 2024.

The logic model (Figure 1) explains the relationship between the issue, the Regulations, and the incremental impacts (benefits and costs). The issue under consideration is that storage tanks and loading operations in the petroleum sector emit large quantities of fugitive VOCs that contribute to air pollution. To address this issue, the Regulations establish emissions control measures for new and existing storage tanks and loading operations in the petroleum sector. Compliance with the Regulations would generate environmental and health benefits from improved air quality (due to reduced VOC emissions) and reduced climate change impacts (due to reduced methane emissions). The Regulations would also result in recovered products (gasoline and crude oil) as a result of reduced evaporative emissions from regulated facilities. The sale of these recovered products would provide additional production benefits. There are also possible health benefits due to reduced exposure to carcinogenic substances (such as benzene); however, these benefits could not be quantified due to technical and data limitations.

Addressing the issue would require that the industry assume compliance costs to implement the regulatory requirements and administrative costs to demonstrate compliance with those requirements. In addition, the Government would incur administrative costs to enforce the Regulations. A breakdown of these costs is included in the following logic model.

Figure 1: Logic model for the Regulations

Figure 1: Logic model for the Regulations - Text version

The logic model outlines the issue with storage tanks and loading operations in the petroleum sector, which are responsible for emitting significant quantities of volatile organic compounds (VOCs). These emissions have been identified to negatively impact both human health and the environment. In response, the proposed Regulations aim to establish control measures for emissions from both new and existing storage tanks and loading operations within this sector. As a result of implementing these Regulations, several key outcomes are anticipated. First, there will be a reduction in emissions of specific carcinogens, such as benzene, leading to health benefits characterized by decreased exposure to these carcinogens and overall improved air quality. Concurrently, the reduction of non-methane VOC emissions will further augment environmental and health benefits, also enhancing the air quality. The environment will experience additional benefits due to a reduction in methane emissions, with potential production benefits arising as facilities might recover products from these reduced VOC emissions. This reduction in methane emissions also translates into notable climate change benefits, as it will directly contribute to mitigating greenhouse gas damages. The industry will carry initial capital costs for the purchase and installation of compliant equipment, alongside operational and maintenance expenses for this new equipment. Furthermore, there will be administrative costs as facilities will have to regularly test, monitor, and report in alignment with the proposed Regulations. The Government will also bear costs in terms of program administration, compliance promotion, and enforcement. Finally, the model indicates that there are certain quantifiable impacts stemming from the proposed Regulations, while some impacts remain unquantifiable.

Data and assumptions

The modelling of benefits, costs and emissions was informed by extensive research and consultation with interested parties. Data were collected from a variety of Canadian and international government publications, databases, academic papers, and submissions from industry sources. Specifically, multiple vendors and contractors were contacted to validate representative costs on tank upgrades and vapour control systems. Industry representatives were also consulted on key assumptions and data. Their input was incorporated into the analysis to improve estimates for equipment inventories, as well as inspection, repair, and administrative costs.

Key sources of information include the following: Statistics Canada; National Pollutant Release Inventory; National Air Pollution Surveillance Program; AP-42, Fifth Edition, Volume 1, Compilation of Air Pollutant Emissions Factors from Stationary Sources; Canadian Fuels Association; Canadian Association of Petroleum Producers; Oil Sands Magazine; 2016 Report – Canada’s Downstream Logistical Infrastructure: Refining, Biofuel Plants, Pipelines, Terminals, Bulk Plants & Cardlocks (PDF) — Kent Group Ltd.; information gathered by the Department under CEPA; and Clean Air Sarnia and Area.

Estimation models

A cost-benefit analysis (CBA) was developed to quantify and monetize benefits and costs, which includes an estimate of fugitive VOC releases (further detailed below) in the baseline and regulatory scenarios. Once fugitive VOC releases were estimated, the Department’s Energy, Emissions and Economy Model for Canada (E3MC) and Global Environmental Multi-scale - Modelling Air quality and Chemistry (GEM-MACH) models were used to determine changes in ambient air concentrations between the two scenarios. Health Canada’s Air Quality Benefits Assessment Tool (AQBAT) model was then used to estimate the health impacts of these changes. Similarly, the Department’s Air Quality Valuation Model 2 (AQVM2) was used to estimate the environmental benefits. These models are peer-reviewed.

The CBA model, developed by the Department, was used to estimate VOC emissions by first estimating the number of tanks and loading racks. Second, the emission factors for the tanks were estimated for both the baseline and regulatory scenarios. Third, the fugitive VOC emissions in the baseline and regulatory scenarios were calculated by multiplying the number of tanks and loading racks with their emission factors. Fourth, incremental VOC emissions (emissions reductions) were calculated by obtaining the differences between the baseline and regulatory VOC emissions.

E3MC, developed by the Department, was used to prepare the baseline air quality data that feeds into the GEM-MACH model. E3MC is an economy-wide model that captures the interactions between the environment and the economy. E3MC has two components: Energy 2020 and The Informetrica Model. Energy 2020 is an integrated, multi-region, multi-sector North American model that simulates the supply, price, and demand for all fuels. The Informetrica Model is a macroeconomic model of the Canadian economy used to examine consumption, investment, production, and trade decisions. The baseline air quality data comes from Energy 2020. This baseline contains various estimates of air pollutants such as VOCs, particulate matter (PM), sulphur dioxides, nitrogen oxides, and more.

The GEM-MACH model, also developed by the Department, is an air quality modelling system that generates data on the changes in air pollutant concentrations using the VOC emission reductions estimated by the CBA model. The model’s forecast domain covers most of Canada, the continental United States, and northern Mexico. Version 3.0 of the GEM-MACH model, which has been operational since 2019, was used in this analysis. The model generated data for 2031 that demonstrate incremental impacts (i.e. differences between the baseline and regulatory scenarios) for ozone, particulate matter up to 10 micrometres in size, carbon monoxide, and visual range. However, there were minimal impacts on PM_2.5, sulphur dioxide and nitrogen dioxide.

AQBAT, a model developed by Health Canada, was used to estimate the human health benefits (i.e. the impacts of avoided adverse health effects and the dollar value of the reduction in health damages) due to modelled changes in air pollutant concentrations generated by the GEM-MACH model. The model incorporates the changes in air pollutant concentrations along with data on Canadian populations, health endpoint occurrence rates and concentration-response functions to estimate the number of adverse morbidities and premature mortalities. In addition, AQBAT provides economic valuation estimates of those health impacts, considering the potential social, economic and public welfare consequences of the health outcomes, including medical costs, reduced workplace productivity, pain and suffering, as well as impacts of increased mortality risk.

The AQVM2 model, developed by the Department, was used to estimate environmental benefits using the modelled changes in air pollutant concentrations generated by the GEM-MACH model. This is a computer simulation tool that estimates the value of the environmental costs or benefits associated with a change in air quality. In this analysis, the baseline air quality for a modelled year was compared to the air quality due to the Regulations to estimate the incremental impacts on the environment (environmental benefits). The incremental impacts were then valued in monetary terms. There are three types of environmental impacts in the AQVM2: changes to crop productivity from summer ozone levels; changes in visibility from particulate matter; and surface soiling of buildings from coarse particulates. Valuation of the three types of impacts sums up to the environmental benefits for the Regulations.

Changes to analysis since publication of Proposed Regulations

Updates to benefit analysis

The list of regulated facilities has grown since the publication of the Proposed Regulations in the Canada Gazette, Part I (it was previously estimated that 243 facilities would be subject to the Regulations) due to increased data availability. However, specific locational data was only available for a subset of these new regulated facilities. Since the modelling of air quality impacts is dependent on specific location, the estimated emissions reductions of these facilities were not included in the modelling of air quality impacts (health and environmental). Of the 191 additional regulated facilities, most are bulk plants, which typically have lower emissions than other regulated facilities. As a result, the addition of these facilities accounts for only 5% (25 500 tonnes) of total reductions in VOC emissions under the Regulations.

To account for the incremental monetized environmental and health benefits of the inclusion of these facilities in the Regulations, their impacts were approximated using a benefit-per-tonne (BpT) approach. Using results from AQBAT and AQVM2 models for the proposed Regulations on total benefits ($) as well as the initial VOC emissions (tonnes) input, an average nationwide BpT was developed for the year 2031. This was done by dividing the total national monetized health or environmental benefits by the national VOC reductions using the 2031 air quality modelling outputs. The 2031 BpT was then extrapolated over the analytical period using the population growth rate for both health and environmental benefits. This BpT was then used as a basis to account for the incremental benefits resulting from the VOC emission reductions coming from the new facilities.

Updates to cost analysis

During consultation on the Proposed Regulations, some companies impacted by the one-year timeline for high benzene tanks indicated that they have begun initial engineering work on new emissions control equipment to aid in meeting the timeline, although they did not intend to finalize designs or install equipment prior to the Regulations coming into force. The Department estimates that five companies incurred costs in 2024 for this reason, in each case amounting to 2% of the cost of retrofitting a new vapour control unit on a high benzene internal floating roof tank ($101,776 per company). In addition, the high benzene tanks at one facility were recently addressed through the Interim Order, meaning this facility would not require additional retrofitting of a new vapour control unit on a high benzene internal floating roof tank ($5,088,811). Together, these costs amount to a total reduction in costs of $5,597,692 relative to what was estimated for the Proposed Regulations.

As mentioned above, additional facilities were identified as in scope of the Regulations, since the publication of the Proposed Regulations. The compliance and administrative costs for the additional facilities were calculated using the same methodology and input costs as for the existing facilities captured in the analysis for the Proposed Regulations. The inclusion of these additional facilities in the analysis leads to an increase in compliance costs of less than $100 million.

Baseline scenario

In the baseline scenario, regulated facilities would continue to meet existing regulatory requirements or continue voluntary practices for controlling VOC emissions. This includes voluntary national CCME instruments and mandatory provincial or municipal measures.^{footnote 27} Regulated facilities that are currently subject to existing regulatory requirements are shown in Table 6.

Table 6: Regulated facilities that are currently subject to existing regulatory requirements

Province or Territory	Scope of coverage	Cities	Facility count	Details of coverage
NL	Province-wide	All	15	Vapour control and storage tank design, inspection and maintenance
QC	Province-wide	All	40	Storage tank design
QC	Montreal Municipality	Montréal	7	Vapour control and storage tank design, inspection and maintenance
QC	Montreal Municipality	Montréal-East	2	Vapour control and storage tank design, inspection and maintenance
ON	Province-wide	All	71	Vapour control and storage tank design, inspection and maintenance
BC	Metro Vancouver Municipality	Vancouver	1	Vapour control for gasoline loading
BC	Metro Vancouver Municipality	North Vancouver	1	Vapour control for gasoline loading
BC	Metro Vancouver Municipality	Burnaby	6	Vapour control for gasoline loading
Other	n/a	n/a	291	No provincial or municipal practices
National	n/a	n/a	434	CCME practices

Regulatory scenario

Under the regulatory scenario, all regulated facilities are required to implement the emissions control equipment, inspection and record-keeping requirements, as summarized in the “Description” section. Tanks and loading equipment that were in service before the date of final publication are subject to a phased implementation period of one to seven years. Tanks and loading equipment that enter service after registration of the Regulations are immediately subject to all requirements.

Incremental benefits

The primary objective of the Regulations is to improve human health and the environment. In addition, the Regulations would yield co-benefits to climate change and recovered products.

The Regulations would reduce VOC emissions, including benzene emissions, by approximately 488 kt over the analytical period (as illustrated in Figure 2). The reduction in VOC emissions is expected to improve air quality, thereby generating health and environmental benefits. Another co-benefit of the Regulations is a reduction in methane emissions of approximately 7.8 kt over the analytical period. The reduction in methane emissions is expected to reduce greenhouse gas (GHG) emissions and thus reduce climate damages.

Figure 2: VOC emissions (excluding methane) in the baseline and regulatory scenarios

Figure 2: VOC emissions (excluding methane) in the baseline and regulatory scenarios - Text version

Figure 2 shows the VOC emissions in the baseline and regulatory scenarios, excluding methane emissions. Although VOC releases contain methane releases, they have to be excluded from the quantification of VOCs, as methane is a greenhouse gas. The baseline VOC emissions are assumed constant at 35 287 tonnes annually over the analytical period (2025–2045), following consultations with the industry. However, following implementation of the proposed Regulations, VOC emissions decline to 14 326 tonnes in 2026 and to 9 742 tonnes in 2031, then are constant thereafter due to expected full compliance.

Overall, the Regulations would yield total benefits of approximately $1.5 billion to the public and industry over the analytical period, or $88.3 million annualized. Specific benefits, including health, environmental, climate change and production benefits are discussed below.

Health benefits

Air quality improvements are expected in the form of reductions in the contribution of VOCs to ambient concentrations of particulate matter (PM_2.5) and ground-level ozone as well as in releases of carcinogenic VOCs, including benzene. Consequently, the estimated VOC emission reductions attributed to the Regulations would reduce adverse impacts on the health of people living in Canada associated with these pollutants.

Health benefits from reductions of VOC releases

Extensive scientific research in Canada^{footnote 28} and around the world has shown that any increase in air pollution exposure results in an increase in per capita risk of adverse health effects, including exacerbation of respiratory symptoms, development of disease and premature death. The relationship between exposure to each pollutant (e.g. PM_2.5 or ground-level ozone) and the associated change in health risk has been quantified for individual health outcomes. Health Canada’s AQBAT incorporates those relationships along with data on Canadian populations to estimate the change in the incidence of illnesses and adverse health outcomes, including the number of premature deaths, associated with a change in air pollution. In addition, AQBAT provides economic valuation estimates for those health impacts, considering the potential social, economic, and public welfare consequences of the health outcomes, including medical costs, reduced productivity, pain and suffering, and the impacts of changes in mortality risk.

As outlined in the Regulatory Impact Analysis Statement published with the Proposed Regulations in the Canada Gazette, Part 1,^{footnote 29} air quality modelling was undertaken for the year 2031^{footnote 30}, the year of full implementation for reductions, which begin in 2026. For the analysis of the final Regulations, Health Canada used the modelled air quality results for 2031 and the aforementioned BpT approach. This combined with the incremental VOC reductions from the additional facilities were used to estimate the incremental monetized health impacts, on top of the impacts to health from the facilities included under the Proposed Regulations.

For the facilities considered in the analysis for the Proposed Regulations, air quality modelling for 2031 was undertaken using GEM-MACH and health impacts were estimated using AQBAT. Health Canada extrapolated the health impact results from 2031 to the other calendar years, factoring changes in population and the estimated VOC emission reductions for each year. It was estimated that over the period of analysis, air quality improvements attributed to the Regulations would result in 150 fewer premature deaths. In addition, better air quality is expected to result in 31 000 fewer days of asthma symptoms among asthmatics aged 5 to 19, and 91 000 fewer days of restricted activity among non-asthmatics.

To account for the incremental monetized benefits of the inclusion of additional facilities in the final Regulations, health impacts were estimated by the BpT approach that involves multiplying the additional VOC emissions reductions for these facilities by an annual BpT. The annual BpT was approximated from the 2031 air quality modelling done for the Proposed Regulations by dividing the total national monetized health benefits by the national VOC reductions from the Proposed Regulations. The 2031 national BpT was then extrapolated over the analytical period using the population growth rate. Finally, the annual national BpTs were multiplied by the annual VOC reductions from the additional facilities captured within the final Regulations to estimate the incremental health benefits associated with these facilities. The approach to estimate BpT is detailed in a Health Canada publication entitled Health Benefits per Tonne of Air Pollutant Emissions Reduction.^{footnote 31}

The total present value of health benefits resulting from these air quality improvements at the national level is estimated at $1.1 billion (2022 Canadian dollars) for the analytical period.

As shown in Table 7, monetized health benefits from the Regulations are most significant in Quebec, British Columbia, Alberta, and Ontario. These four provinces account for 91% of the total benefits. Provincial health benefits reflect not only the emission reductions, but also differences in atmospheric conditions and reduced population exposure to these pollutants. The provinces that experience the largest health benefits, in absolute terms, are the provinces with the largest populations and the highest levels of population exposure. Additionally, wind direction and atmospheric conditions play a critical role in the fate and transport of air pollutants and human exposure to air pollution. Emission reductions at facilities that are located upwind of large population centres can have a greater health impact than similar emission reductions at facilities in more remote locations, or in locations that are downwind of major population centres. As a result, health benefits by province may not be directly proportional to emission reductions by province.

Approximately 51% of the health benefits resulting from reduced VOC releases are associated with lower ambient levels of PM_2.5, and 48% are a result of reductions in ground-level ozone. Less than 1% are due to the reduction in levels of other pollutants captured in Health Canada’s model (AQBAT), including nitrogen dioxide.

Table 7: Monetized health benefits (2025–2045, in millions of 2022 dollars, discounted at 2%)

Province or Territory	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0.0	0.3	0.5	0.5	0.5	1.8
PE	0.0	0.2	0.2	0.2	0.2	0.9
NS	0.0	4.2	4.7	4.5	4.4	17.8
NB	0.0	1.3	1.4	1.4	1.3	5.4
QC	0.0	69.1	81	80.2	78.8	309.0
ON	0.0	36.9	44.0	45.1	45.6	171.7
MB	0.0	11.8	13.7	13.8	13.8	53.1
SK	0.0	3.5	3.7	3.5	3.3	14.0
AB	0.0	50.5	60.9	65.0	67.7	244.1
BC	0.0	63.6	75.2	75.5	75.1	289.5
YT	0.0	0.1	0.1	0.1	0.1	0.3
NT	0.0	0.2	0.2	0.2	0.2	0.8
NU	0.0	0.8	0.8	0.7	0.7	3.0
Canada	0.0	242.7	286.5	290.8	291.6	1,111.6

These values represent economic benefits considering the potential welfare impacts associated with treatment costs, lost productivity, pain and suffering, and changes in mortality risk. For a detailed explanation of these values see the AQBAT 3.0 User Guide.^{footnote 32}

Health benefits of reductions in carcinogenic substances

The Regulations will reduce emissions of toxic substances such as benzene, a known human carcinogen. Health Canada recommends reducing exposure to carcinogens like benzene wherever feasible. Although the benefits of these reductions were not quantified, they are expected to increase the overall health benefits estimated above.

The health risks of benzene exposure associated with the facilities and equipment subject to the Regulations were assessed using the same methodology as the Government of Canada’s Screening Assessment – Petroleum Sector Stream Approach: Natural Gas Condensates and considering information from the Benzene Releases from Gasoline Stations: Implications for Human Health report. The analysis indicates that the Regulations would address the short- and long-term benzene exposure risks identified in the Natural Gas Condensates assessment, and other similar risks.

Other impacts

Modelling conducted to support the development of the Regulations indicated potential short-term benzene exposure risks during gasoline truck loading activities, even at very small facilities; and in some cases, potential long-term benzene exposure risks. In February 2024, the Government of Canada published a Notice of intent to consult on a risk management strategy respecting benzene emissions from gasoline stations.^{footnote 33} The Department intends to undertake further analysis on benzene exposure at very small facilities that are exempt from the Regulations to assess their health risks as part of this initiative.

Environmental benefits

VOC emissions can lead to the formation of particulate matter and ozone, both of which negatively affect vegetation, soils, water, wildlife, materials, as well as the overall quality of the ecosystem. Chronic exposure to ozone may result in crop yield losses, degradation of vegetation, reduced timber growth and premature livestock mortalities and illnesses. Degraded visibility associated with particulate suspension and smog may negatively affect residential welfare, tourism and the benefits from outdoor recreational activities. Particulate matter deposition is also associated with soiling and structural damage, which may lead to higher cleaning and maintenance costs. It is expected that the Regulations would reduce associated economic costs for the agri-food and forestry industries and therefore result in environmental benefits.

Using AQVM2, the Department estimated the incremental environmental impacts of air quality improvements on soiling, visibility and crop productivity associated with the Regulations. The economic indicators to assess these impacts for soiling, visibility and crop productivity are respectively the avoided cost to households, the change in household welfare and the change in sales revenues for crop producers. Air quality modelling was undertaken for the year 2031. To account for additional environmental benefits from incremental VOC reductions under the Regulations, a BpT approach was applied – consistent with the method used for incremental health benefit modelling. The environmental benefits of the Regulations were estimated by adding the incremental benefits to the Regulations from additional facilities to the environmental benefits estimated for the proposed Regulations. The BpT approach was used to estimate these additional benefits for 2031, which were then extrapolated across the regulatory period, adjusting using population changes and expected VOC reductions.

The total present value of environmental benefits resulting from air quality improvements attributable to the Regulations is estimated at $15.4 million for the analytical period. Table 8 presents the cumulative environmental benefits, broken down by impact and by province/territory. The largest portion of these benefits is in Alberta, which is consistent with the larger emission reductions occurring in this province. The estimates should be considered conservative since only the impacts on soiling, visibility and agricultural productivity were assessed by the AQVM2. As pollutant emissions can travel over large distances, environmental benefits in some provinces may be partly attributable to emission reductions from adjacent provinces.

Table 8: Cumulative environmental benefits (2025–2045, in millions of 2022 dollars, discounted at 2%)^{footnote 37}

Province or Territory	Soiling/Avoided costs for households	Visibility/Change in welfare for households	Crop productivity/Change in sales revenues for crop producers	Total
NL	0.01	0.03	0.01	0.05
PE	0.01	0.04	0.01	0.06
NS	0.05	0.17	0.02	0.24
NB	0.01	0.04	0.01	0.06
QC	0.60	1.72	0.44	2.76
ON	0.26	0.16	1.66	2.07
MB	0.17	0.38	0.19	0.74
SK	0.14	0.28	0.45	0.87
AB	1.58	3.29	0.60	5.47
BC	0.97	2.00	0.03	3.00
YT	0.00	0.00	0.00	0.01
NT	0.005	0.01	0.00	0.02
NU	0.02	0.04	0.01	0.07
Canada	3.84	8.16	3.43	15.43

Over the analytical period, avoided household cleaning costs of about $3.8 million are expected. These benefits should be considered conservative as they do not account for avoided cleaning costs in the commercial and industrial sectors.

Based on the willingness to pay for improved visual range and air quality changes, the AQVM2 estimates the monetary change in welfare for different levels of deciviews.^{footnote 34} Welfare gains from improved visibility in the residential sector are approximately $8.2 million over the analytical period.

Reductions in VOC emissions decrease ambient concentrations of ground-level ozone, which may result in higher crop yields. National benefits from increased crop productivity, expressed in the present value of sales revenue over the analytical period, are expected to be approximately $3.4 million, with most of the benefits accruing in Ontario.

Reducing VOC emissions may also have other environmental benefits. For instance, the associated reduction in concentrations of ozone and particulate matter may benefit forest ecosystem health, while visibility improvements may result in higher enjoyment of recreation and increased tourism revenues. In addition, lower levels of ground-level ozone and particulate matter may reduce the risks of illness or premature death in sensitive wildlife or livestock populations, potentially resulting in avoided treatment costs or lower economic losses for the agri-food industry.

Production benefits

Evaporative emissions from storage and loading operations result in the release of liquid hydrocarbons (e.g. crude oil and gasoline) to the atmosphere as VOC vapours. Consequently, facilities encounter economic losses of liquid hydrocarbon products. The installation, inspection and maintenance of vapour controls on storage tanks (e.g. floating roofs) and loading racks (e.g. vapour recovery units) would allow such products to be recovered throughout the distribution network. This would lead to some economic benefits to storage and loading facilities.

Production benefits from recovered products were calculated by first estimating the volume of recovered products (crude oil and gasoline) from various facilities as a result of complying with the Regulations. Table 9 and Table 10 provide the volume estimates of the recovered products.

Table 9: Volume estimates of recovered gasoline (thousand litres)

Province or Territory	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0	2 669	2 669	2 669	2 669	10 667
PE	0	1 119	1 119	1 119	1 119	4 478
NS	0	4 059	5 467	5 467	5 467	20 459
NB	0	1 463	5 133	5 133	5 133	16 861
QC	0	10 522	12 512	12 512	12 512	48 057
ON	0	8 744	21 552	21 552	21 552	73 400
MB	0	3 861	5 261	5 261	5 261	16 861
SK	0	6 506	11 357	11 357	11 357	40 578
AB	0	24 746	32 959	32 959	32 959	123 625
BC	0	9 284	11 136	11 136	11 136	42 692
YT	0	56	56	56	56	224
NT	0	697	697	697	697	2 787
NU	0	509	509	509	509	2 037
Canada	0	74 236	110 427	110 427	110 427	405 518

Table 10: Volume estimates of recovered crude oil (thousand litres)

Province or Territory	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0	0	1	1	1	4
PE	0	0	0	0	0	0
NS	0	0	0	0	0	0
NB	0	1	3	3	3	10
QC	0	6	13	13	13	45
ON	0	2	6	6	6	19
MB	0	1	3	3	3	9
SK	0	62	77	77	77	293
AB	0	97	142	142	142	522
BC	0	17	18	18	18	71
YT	0	0	0	0	0	0
NT	0	0	1	1	1	2
NU	0	0	0	0	0	0
Canada	0	185	263	263	263	974

The production benefits (the dollar value of the recovered products) were then estimated by multiplying the volume of recovered products by the forecasted prices of those recovered products obtained from the E3MC.^{footnote 35} For gasoline, provincial volumes were multiplied by provincial prices. However, for crude oil, provincial volumes were multiplied by the Canadian average price of heavy and light crude oil, as crude oil could not be differentiated between heavy and light (note that prices were not available at the provincial level). Table 11 and Table 12 provide the average forecasted fuel prices used in this estimation. The prices were calculated based on the wholesale price without fuel taxes. Gasoline prices were forecasted to increase within the E3MC, while crude oil prices fluctuate then fall stagnant over the years.

Table 11: Average forecasted prices of gasoline ($ per litre)

Province or Territory	2025	2026–2030	2031–2035	2036–2040	2041–2045
NL	0.90	0.91	0.93	0.94	0.94
PE	0.83	0.84	0.86	0.87	0.88
NS	0.79	0.80	0.81	0.82	0.83
NB	0.80	0.81	0.83	0.84	0.85
QC	0.85	0.86	0.88	0.88	0.89
ON	0.81	0.82	0.84	0.84	0.85
MB	0.84	0.85	0.87	0.88	0.89
SK	0.86	0.87	0.89	0.89	0.90
AB	0.83	0.84	0.86	0.86	0.87
BC	0.99	1.00	1.02	1.03	1.04
YT	1.20	1.21	1.24	1.25	1.26
NT	1.08	1.09	1.12	1.13	1.14
NU	1.20	1.21	1.24	1.25	1.26

Table 12: Average forecasted prices of crude oil ($ per barrel)

Type of crude oil	2025	2030	2035	2040	2045
Canada-heavy crude	76.75	81.59	77.49	76.89	76.28
Canada-light crude	94.21	99.09	98.46	97.85	97.25
Canada-average	85.48	90.33	97.97	87.37	86.76

The production benefits from recovered crude oil was estimated at $68 million, while that of recovered gasoline was estimated at $282 million over the analytical period, for a total of $350 million in recovered products (Table 13).

Table 13: Production benefit estimates (in millions of 2022 dollars, discounted at 2%)

Province or Territory	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0	2.3	2.2	2.0	1.8	8.2
PE	0	0.9	0.8	0.7	0.7	3.1
NS	0	3.0	3.7	3.4	3.1	13.2
NB	0	1.1	3.8	3.5	3.2	11.6
QC	0	8.8	10.1	9.2	8.4	36.6
ON	0	6.7	15.5	14.2	13.0	49.4
MB	0	3.1	4.1	3.7	3.4	14.2
SK	0	10.3	14.1	12.8	11.6	48.8
AB	0	27.1	34.1	31.0	28.2	120.3
BC	0	10.0	10.9	9.9	9.0	39.8
YT	0	0.1	0.1	0.1	0	0.2
NT	0	0.7	0.7	0.6	0.6	2.6
NU	0	0.6	0.5	0.5	0.4	2.0
Canada	0	74.6	100.6	91.6	83.4	350.1

The analysis assumes that (1) the recovered products are exported, combusted abroad, and therefore do not contribute to domestic GHG emissions (as they are not part of domestic consumption); or (2) even if recovered products are consumed locally, they replace the same product and therefore their combustion does not result in incremental GHG emissions.

Climate change benefits

Light hydrocarbons dissolved in crude oil can include methane, which can evaporate from crude oil during storage and loading operations; therefore, reducing fugitive VOC releases from the storage and loading of crude oil would also result in the reduction of methane emissions. Methane is a GHG that contributes to global warming, it is 28 times more potent than carbon dioxide emissions over the short term. Climate change benefits from reduction of methane emissions were calculated using the social cost of methane.^{footnote 36} The first step involved estimating the annual reductions in methane emissions attributable to the Regulations. The annual methane emissions were then combined with the associated discounted social cost of methane values to provide the estimated benefits of annual reductions in methane emissions. Table 14 provides the estimated incremental reduction in methane emissions.

The Regulations would reduce methane emissions by approximately 7.8 kt over the analytical period, resulting in climate change benefits (reduced climate change damages) of $24.3 million.

Table 14: Estimated reduction in methane emissions (kilotonnes)

Province or Territory	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0	0	0	0	0	0
PE	0	0	0	0	0	0
NS	0	0	0	0	0	0
NB	0	0	0	0	0	0.1
QC	0	0.1	0.1	0.1	0.1	0.3
ON	0	0	0.1	0.1	0.1	0.2
MB	0	0.1	0.1	0.1	0.1	0.4
SK	0	0.5	0.6	0.6	0.6	2.2
AB	0	0.9	1.1	1.1	1.1	4.1
BC	0	0.1	0.1	0.1	0.1	0.5
YT	0	0	0	0	0	0
NT	0	0	0	0	0	0
NU	0	0	0	0	0	0
Canada	0	1.7	2.0	2.0	2.0	7.8

Incremental costs

Overall, the Regulations would impose a total cost of approximately $1.2 billion to the industry and the Government over the analytical period, or $70.7 million annualized. Below is a breakdown of the cost components.

Industry costs

In order to comply with the Regulations, the industry would incur capital and operating costs (compliance costs). In addition, in order to demonstrate compliance with the Regulations, the industry would also incur testing, monitoring, and reporting costs (administrative costs). The total costs to the industry are estimated at $1.19 billion over the analytical period.

Capital costs

The Regulations would impose costs on the industry to install emission control equipment on large aboveground atmospheric storage tanks and truck, rail and marine loading equipment. Depending on the properties of the petroleum liquids stored and the size of the tanks, the industry incurs costs to equip tanks with a vapour control system, an internal floating roof, an external floating roof, or a pressure-vacuum valve. The industry would also bear costs to equip loading racks with vapour control systems, depending on the product properties and throughput of the loading racks. The capital costs are expected to start in 2026 onwards as regulated facilities are given one to seven years to install emissions control equipment.

Main tank capital costs associated with the Regulations include performing complete replacement of floating roof seals, retrofitting fixed roof tanks with a new internal floating roof, and installing vapour control system on a fixed roof tank.^{footnote 38} Loading operations capital costs associated with the Regulations include installing vapour balancing units at large bulk plants and installing vapour recovery or destruction systems at truck, rail and marine loading racks.^{footnote 39} The first step in estimation of equipment capital costs was to compile the unit costs for the new emissions control equipment to be installed (one-time only) in the storage tanks and loading racks containing liquid petroleum products. The second step was to identify and document the storage tanks and loading racks that require the equipment using reported emissions, data gathered by the Department under CEPA, publicly available information and satellite imagery. The third step was to obtain the facility-level capital costs by multiplying the unit equipment costs by the number of each type of storage tank or loading racks that require the new equipment. The fourth step was to obtain the total capital costs by aggregating facility-level capital costs. Table 15 provides the estimated unit equipment costs. These costs were estimated by the Department using factored engineering methods and were intended to capture the total installed cost at a typical site. Data was sourced directly from vendors of emissions control equipment and storage tank manufacturers, with validation from interested parties in the oil and gas sector.

Table 15: Estimated unit equipment costs

Category	Regulatory requirement	Fuel product	One-time capital cost (in 2022 dollars)	Estimated quantity required table g1 note a
Tanks	Perform complete replacement of floating roof seal (26 m diameter tank)	Gasoline / crude oil	$516,556	194
	Retrofit fixed roof tank with new internal floating roof (26 m diameter tank)	Gasoline	$885,524	209
	Retrofit vapour control unit on high benzene internal floating roof tank	Benzene	$5,088,811	15 table g1 note b
	Install vapour balancing system at bulk plant	Gasoline	$241,084	164
Loading racks	Vapour control system at small truck/rail terminal (< 150 000 m3/year)	Gasoline / crude oil	$2,361,397	41
	Vapour recovery system at medium truck/rail terminal (< 450 000 m3/year)	Gasoline / crude oil	$4,014,375	22
	Vapour recovery system at large truck/rail terminal (> 450 000 m3/year)	Gasoline / crude oil	$8,737,169	10
	Marine loading vapour recovery system (approximatively 1 500 000 m3/year)	Gasoline / crude oil	$13,637,068	17
Table g1 note(s) Table g1 note a Values may not add up due to some facilities tying multiple tanks or loading racks into one common vapour control unit Return to table g1 note a referrer Table g1 note b The Department estimates 15 high benzene tanks will be retrofitted based on information provided by industry representatives Return to table g1 note b referrer

The estimated total capital costs for installing emission control equipment on tanks and loading operations are approximately $905 million from 2026 to 2030 (see Table 16), with a significant portion, around $735 million, expected to be incurred in 2026. These costs differ across provinces, with the highest expected costs in Alberta, followed sequentially by Ontario, Quebec, British Columbia, Saskatchewan, Manitoba, Nova Scotia, New Brunswick, Newfoundland and Labrador, and Prince Edward Island. Installation of emission control equipment on aboveground storage tanks is expected to cost $378 million, while installation of this equipment in loading operations is expected to cost $527 million.

Table 16: Incremental capital costs by province/territory — Total (in millions of 2022 dollars, discounted at 2%)

Province or Territory	Cost related to emission control equipment on storage tanks	Cost related to emission control equipment on loading racks	Total cost
NL	4.6	6.1	10.7
PE	0.5	4.3	4.8
NS	1.9	28.6	30.5
NB	7.5	5.7	13.2
QC	40.5	102.1	142.6
ON	92.7	64.3	157.0
MB	13.8	31.9	45.6
SK	48.0	59.2	107.1
AB	134.0	114.0	248.0
BC	30.3	94.7	125.0
YT	0.5	0.2	0.7
NT	3.1	16.1	19.2
NU	0.5	0	0.5
Canada	377.8	527.2	905.0

Operating costs

The Regulations would require the industry to regularly inspect and repair their storage tanks, loading racks and emission control equipment. Lower explosive level testing is required for internal floating roof tanks, and seal gap inspection is required for external floating roof tanks. These operating costs are expected to start in 2026 as regulated facilities are given one to seven years to install emissions control equipment.

The first step in computing operating costs was estimating the hours of skilled labour required for inspecting, repairing, and maintaining the emissions control equipment installed in storage tanks and loading racks. Second, the annual frequencies for carrying out these activities within the year were estimated. Third, the hourly wage rate for skilled labour was estimated. Fourth, the annual equipment operating costs were estimated by multiplying the hours of labour required for each activity by the annual frequencies for the activity and the hourly wage rate, then aggregating across activities. Fifth, the facility-level annual operating costs were obtained by multiplying the annual equipment operating costs by the number of each type of storage tank or loading rack where new equipment is installed. Sixth, the total annual operating costs were obtained by aggregating facility-level annual operating costs. Table 17 summarizes the annual equipment operating costs for tanks and loading racks. These costs were estimated using data sourced directly from vendors of emissions control equipment and companies providing inspection, repair, and maintenance services, with validation from interested parties in the oil and gas sector.

Table 17: Estimated annual operating costs

Category	Regulatory requirement	Product	Annual operating cost (in 2022 dollars)
Tanks	Incremental increase in tank operation and maintenance costs after installation of floating roof, including 3 person-weeks of labour per year for inspection and maintenance, increased parts cost for instrumentation and auxiliaries	Gasoline/crude oil	$20,294
	Lower explosive level and visual inspection of internal floating roof at a site with 15 to 20 tanks	Gasoline/crude oil	$22,669
	Vapour control system on tank	Benzene	$100,832
	Vapour balancing system	Gasoline	$11,335
Loading racks	Vapour control unit at small truck/rail terminal (< 150,000 m3/yr)	Gasoline/crude oil	$94,928
	Vapour recovery unit at medium truck/rail terminal (< 450,000 m3/yr)	Gasoline/crude oil	$100,832
	Vapour recovery unit at large truck/rail terminal (> 450,000 m3/yr)	Gasoline/crude oil	$106,735
	Marine loading vapour recovery unit (approximately 1,500,000 m3/yr)	Gasoline/crude oil	$130,349

The annual operating cost estimates are based on the following main assumptions:

• Blended labour rate of $100/hr. This rate allows for indirect costs, such as tools, vehicles, and equipment.
• Inspection intervals for tanks:
• 20-year internal inspection intervals for internal floating roof tanks
  • 20-year replacement intervals for tank floating roof seals
  • 5-year external inspection intervals
  • 1-year secondary seal gap measurement intervals on external floating roofs
• Monthly lower explosive level inspections on internal floating roofs
• Inspection intervals for loading racks:
  • 5-year performance test intervals
  • 1-year leak detection intervals
  • Monthly visual inspection

The total operating costs for both tanks and loading operations are estimated at $279.7 million over the analytical period (Table 18).^{footnote 40} Just like capital costs, operating costs vary by province and are expected to be highest in Alberta, followed by Ontario, Quebec, British Columbia, Saskatchewan, Manitoba, Nova Scotia, Newfoundland and Labrador, New Brunswick and Prince Edward Island in that order. Costs for inspecting, repairing, and maintaining installed emission control equipment for tanks are estimated at $106.9 million (Table 19), while the same costs for loading operations are estimated at $172.8 million (Table 20).

Table 18: Incremental operating costs – Total (in millions of 2022 dollars, discounted)

Province or Territory	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0.0	0.9	1.1	1.0	0.9	3.8
PE	0.0	0.5	0.5	0.5	0.4	1.9
NS	0.0	2.1	2.4	2.2	2.0	8.7
NB	0.0	1.3	1.6	1.5	1.3	5.7
QC	0.0	9.4	10.8	9.8	8.9	38.8
ON	0.0	8.9	11.6	10.5	9.5	40.6
MB	0.0	4.0	4.8	4.4	3.9	17.1
SK	0.0	9.5	11.7	10.6	9.6	41.3
AB	0.0	18.6	24.5	22.2	20.1	85.3
BC	0.0	7.4	8.9	8.0	7.3	31.6
YT	0.0	0.0	0.1	0.0	0.0	0.2
NT	0.0	1.0	1.3	1.1	1.0	4.5
NU	0.0	0.0	0.0	0.0	0.0	0.1
Canada	0.0	63.7	79.2	71.8	65.0	279.7

Table 19: Incremental operating costs – Tanks (in millions of 2022 dollars, discounted at 2%)

Province or Territory	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0.0	0.2	0.2	0.2	0.2	0.8
PE	0.0	0.0	0.0	0.0	0.0	0.1
NS	0.0	0.1	0.1	0.1	0.1	0.4
NB	0.0	0.4	0.6	0.5	0.5	2.0
QC	0.0	3.3	3.9	3.5	3.2	13.9
ON	0.0	5.1	7.3	6.6	6.0	25.0
MB	0.0	0.8	1.2	1.1	1.0	4.0
SK	0.0	2.7	3.9	3.5	3.2	13.3
AB	0.0	7.7	11.9	10.8	9.8	40.2
BC	0.0	1.4	1.9	1.7	1.6	6.6
YT	0.0	0.0	0.0	0.0	0.0	0.0
NT	0.0	0.1	0.2	0.2	0.1	0.6
NU	0.0	0.0	0.0	0.0	0.0	0.0
Canada	0.0	21.8	31.2	28.3	25.6	106.9

Table 20: Incremental operating costs – Loading (in millions of 2022 dollars, discounted at 2%)

Province or Territory	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0.0	0.7	0.8	0.7	0.7	3.0
PE	0.0	0.5	0.5	0.5	0.4	1.9
NS	0.0	2.0	2.3	2.1	1.9	8.3
NB	0.0	0.9	1.0	0.9	0.8	3.7
QC	0.0	6.1	6.9	6.3	5.7	24.9
ON	0.0	3.8	4.3	3.9	3.6	15.6
MB	0.0	3.2	3.6	3.3	3.0	13.1
SK	0.0	6.8	7.8	7.1	6.4	28.1
AB	0.0	11.0	12.5	11.3	10.3	45.1
BC	0.0	6.1	7.0	6.3	5.7	25.0
YT	0.0	0.0	0.0	0.0	0.0	0.2
NT	0.0	0.9	1.1	1.0	0.9	3.9
NU	0.0	0.0	0.0	0.0	0.0	0.0
Canada	0.0	42.0	48.0	43.5	39.4	172.8

Other compliance costs

Other compliance costs, not categorized as capital or operational costs in the previous sections, would amount to $1.5 million over the analytical period. Since publication of the Proposed Regulations, the requirements were revised to remove a large portion of the reports referred to in the “prepare and submit repair and outage reports” item as they were deemed to have low value and impose unnecessary burden for most facilities. Thus, this requirement and total other compliance costs for the Regulations are less than they were estimated in the analysis for the Proposed Regulations.

Total other compliance costs include an upfront cost of $0.5 million for the regulated parties to establish an inspection program and ongoing costs of $1.0 million associated with assisting auditors and government enforcement activities as well as for preparing and submitting repair and outage reports. A detailed breakdown of these costs is presented in Table 21.

Table 21: Other incremental compliance costs (in 2022 dollars, discounted at 2%)

Cost category	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
Upfront	554,488	0	0	0	0	554,488
Development of inspection program	554,488	0	0	0	0	554,488
Ongoing	47,699	269,993	244,546	221,492	200,613	984,348
Assisting auditors/enforcement	47,699	224,827	203,633	184,437	167,050	827,646
Preparing and submitting repair and outage reports	-	45,171	40,912	37,056	33,562	156,701
Total	47,699	824,486	244,546	221,492	200,613	1,538,836

Administrative costs

The Regulations are expected to result in around $8.0 million in incremental administrative costs to industry over the analytical period. This includes one-time costs of less than $0.3 million for the regulated parties to familiarize themselves with regulatory obligations and to complete registration. It also includes annual ongoing costs of about $7.7 million over the analytical period for preparing and submitting annual registration update, and maintaining inspection results, equipment lists, and substance and throughput records. A breakdown of these costs is contained in Table 22.

Table 22: Incremental administrative costs (in 2022 dollars, discounted at 2%)

Cost category	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
Upfront	271,801	0	0	0	0	271,801
Familiarization with regulatory obligations	41,549	0	0	0	0	41,549
Registration	230,252	0	0	0	0	230,252
Ongoing	446,375	2,103,968	1,905,629	1,725,987	1,563,279	7,745,238
Maintaining inspection results	160,025	754,269	683,165	618,763	560,433	2,776,655
Maintaining equipment lists and substance and throughput records	229,833	1,083,310	981,187	888,692	804,915	3,987,938
Preparing and submitting annual registration update	56,517	266,389	241,277	218,532	197,931	980,645
Total	718,175	2,103,968	1,905,629	1,725,987	1,563,279	8,017,038

Government costs

The Regulations will result in program administration, compliance promotion, and enforcement costs for the federal government. The total government costs are estimated at approximately $8.1 million over the analytical period.

Program administration

Program administration is pivotal in the implementation, management and understanding of the Regulations. Key activities include responding to general and technical information or clarification requests, developing technical materials such as comprehensive Frequently Asked Questions and fact sheets, evaluating applications, notices and plans, holding information sessions, processing, analyzing and providing feedback on reports, notices and plans, overseeing permit approvals, and measuring program performance. Total program administration costs are estimated at approximately $4.4 million over the analytical period.

Compliance promotion

Compliance promotion consists of activities undertaken with the goal of raising awareness and understanding of the regulatory requirements for the regulatory community. These include maintaining a stakeholder list, posting and distributing promotional materials, tracking inquiries, sending reminder letters, keeping web content up to date, advertising in trade and association magazines, and attending trade association conferences. Compliance promotion activities are expected to be minimal, as operators are primarily large enterprises that have the resources and capacity to develop a good understanding of their legal obligations on their own. These costs will be assumed annually and are estimated at approximately $0.8 million over the analytical period.

Enforcement costs

Enforcement consists of measures to bring non-compliant operators into compliance. In particular, enforcement of the Regulations will result in incremental costs to the federal government related to training, strategic intelligence assessment work, inspections, investigations, and measures to deal with any alleged violations. The federal government is expected to incur enforcement costs of $2.9 million over the analytical period. This includes a one-time cost of $0.11 million for training enforcement officers and undertaking strategic intelligence assessment work. It also includes total recurring costs of $2.8 million over the analytical period, for inspections, investigations, and measures to deal with alleged violations.

Cost-benefit statement

The results of the CBA are summarized in Tables 23 to 25. The total benefits are estimated to be around $1.5 billion, while the costs are estimated to be around $1.2 billion. The net benefits of the Regulations are estimated to be about $299 million.

The benefits analysis shows that the Regulations would generate $1.1 billion in health benefits and $15.4 million in environmental benefits. Other benefits include $350.1 million in production benefits from recovered products and $24.3 million in climate change benefits from methane emission reduction. Due to the lack of data, the benefits associated with reductions in releases of carcinogenic substances are not quantified, nor monetized.

The cost analysis shows that the industry will incur compliance costs of about $1.20 billion to implement the regulatory requirements. This would include $905 million in capital costs, $280 million in operating costs, and $1.5 million in other compliance costs. In addition, the industry and the government will incur administrative costs of $8.0 million and $8.1 million, respectively.

• Number of years: 21 (2025 to 2045)
• Price Year: 2022
• Present value base year: 2024
• Discount rate: 2%

Table 23: Monetized benefits (in millions of 2022 dollars, discounted at 2%)

Impacted parties	Description of benefits	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total	Annualized value
People in Canada	Health benefits	0.0	242.7	286.5	290.8	291.6	1,111.6	65.3
	Environmental benefits	0.0	3.6	4.2	3.9	3.7	15.4	0.9
	Climate change benefits	0.0	4.9	6.2	6.5	6.8	24.3	1.4
Industry	Production benefits	0.0	74.6	100.6	91.6	83.4	350.1	20.6
All parties	Total benefits	0.0	325.8	397.4	392.8	385.5	1,501.4	88.3

Table 24: Monetized costs (in millions of 2022 dollars, discounted at 2%)

Impacted parties	Description of cost	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total	Annualized value
Industry	Capital costs	0.0	872.3	32.6	0.0	0.0	905.0	53.2
	Operating costs	0.0	63.7	79.2	71.8	65.0	279.7	16.4
	Other compliance costs	0.0	0.8	0.2	0.2	0.2	1.5	0.1
	Administrative costs	0.7	2.1	1.9	1.7	1.6	8.0	0.5
Government	Program administration	0.5	1.2	1.1	1.0	0.9	4.6	0.3
	Compliance promotion	0.1	0.2	0.2	0.2	0.2	0.8	0.05
	Enforcement	0.3	0.8	0.7	0.6	0.6	2.9	0.2
All interested parties	Total costs	1.3	941.2	116.0	75.5	68.4	1,202.3	70.7

Table 25: Summary of monetized costs and benefits (in millions of 2022 dollars, discounted at 2%)

All interested parties	2025	2026–2030	2031–2035	2036–2040	2041–2045	Total	Annualized value
Total benefits	0.0	325.8	397.4	382.8	385.5	1,501.4	88.3
Total costs	1.3	941.2	116.0	75.5	68.4	1,202.3	70.7
Net impact (benefits-costs)	-1.3	-615.4	281.4	317.3	317.1	299.1	17.6

Quantified (non-monetized) and qualitative impacts

• Health benefits of reductions in exposure to carcinogenic substances, like benzene (carcinogenic substances not quantified, non-monetized)

Distributional analysis

Compliance costs and VOC emission reductions differ by province/territory and by facility type. The results of this analysis are presented in Tables 26 and 27.

Within the provinces, Alberta, Ontario, Quebec, British Columbia, and Saskatchewan would make up 85.9% of compliance costs. The same provinces would also account for 84.3% of VOC emission reductions. Costs and emissions reductions relative to the number and size of facilities are somewhat lower in Ontario, Quebec, and British Columbia due to existing provincial and municipal requirements. Alberta has the highest share of compliance costs and VOC emission reductions as the province has the largest share of Canadian crude oil production and refining capacity^{footnote 41}.

Among the various types of regulated facilities, primary terminals, crude oil terminals, and refineries account for 79.2% of compliance costs. Likewise, the same facility types combined account for 81.2% of VOC emission reductions. Primary terminals have the highest compliance costs and VOC emission reductions because they are the most common type of facility, and they typically store and load volatile products (mostly gasoline) in large volumes.

Table 26: Distribution of capital and operational costs and VOC emission reductions by province/territory⁴¹

Province or Territory	Total compliance costs ($million)	Total compliance costs (%)	Total VOC emission reductions (kt)	Total VOC emission reductions (%)
NL	14.5	1.2	8.6	1.8
PE	6.8	0.6	3.4	0.7
NS	39.2	3.3	18.9	3.9
NB	18.9	1.6	17.6	3.6
QC	181.4	15.3	46.1	9.4
ON	197.6	16.7	64.9	13.3
MB	62.7	5.3	24.1	4.9
SK	148.5	12.5	76.8	15.7
AB	333.3	28.1	177.8	36.4
BC	156.6	13.2	45.5	9.3
YT	0.9	0.1	0.2	0.0
NT	23.6	2.0	2.7	0.5
NU	0.6	0.0	1.5	0.3
Canada	1,184.7	100	488	100

Table 27: Distribution of capital and operational costs and VOC emission reductions by type of regulated facility

Facility type	Total compliance costs ($million)	Total compliance costs (%)	Total VOC emission reductions (kt)	Total VOC emission reductions (%)
Primary terminal	383.1	32.3	153.9	31.5
Crude oil terminal	360.9	30.5	127.6	26.2
Refinery	193.8	16.4	114.9	23.5
Refinery terminal	64.4	5.4	36.3	7.4
Chemical facility	59.6	5.0	8.7	1.8
Upgrader	48.7	4.1	21.3	4.4
Bulk plant	73.5	6.2	25.2	5.2
Total	1,184.7	100	488.0	100

Competitiveness analysis

Storage tanks and loading operations are prevalent across the oil and gas value chain and the chemicals sector. Therefore, the impact on competitiveness can be analyzed through three primary lenses:

• Fuel products / Refined products: This category encompasses fuel production and distribution, all gasoline tanks, and crude oil tanks at refineries. It is projected to incur most of the total regulatory costs, approximately 60%.
• Crude oil: This includes upgraders and most crude oil tanks/terminals, which are expected to incur 35% of the total costs.
• Petrochemicals: Representing a smaller, yet significant, portion of the estimated regulatory costs, this sector accounts for 5% of the total costs.

Each of these sectors is large and complex, with storage and loading representing an important but relatively minor part of capital expenditure budgets and operating and maintenance costs. The net incremental costs for the industry, after deducting the value of product recovery, are estimated at $844 million. These costs are expected to be mostly incurred within the first five years following the implementation of the Regulations. In order to contextualize these costs relative to overall industry operating expenses, an analysis was conducted on the financial statements of a sample of publicly traded companies operating regulated facilities, accounting for nearly half (49%) of the compliance cost. Assuming these costs are evenly distributed from 2026 to 2030, they would constitute 0.2% of the annual operating expense average and 0.2% of the industry’s average gross margin for the period from 2018 to 2022. This analysis indicates that the compliance costs are not expected to significantly impact the competitiveness or profitability of the sectors involved, namely fuel production and distribution, crude oil storage, or petrochemical production.

There has been a trend of consolidation at larger urban terminals and bulk plants, which is expected to continue. Although the Regulations exclude very small facilities and provide greater flexibility and lower-cost options for small or medium sized terminals, there is potential that some regulated facilities may close if incremental capital investment in the facility does not have a strong business case. However, a business’s decision to close a regulated facility would be more probable if the facility was already, for other reasons, a candidate for potential closure in the future. As shown above, the incremental compliance costs represent a small fraction of the annual operating expenditures (or falls within the typical variation of annual capital expenditures).

The degree to which production cost may be passed on to consumers in Canada is uncertain. Cost pass through depends on various factors, such as the degree of competition within local markets, regulated price increases in some jurisdictions, distribution constraints, the balance between regional demand of petroleum products and local production capacity in those areas, and currency exchange rates.^{footnote 42} In a full cost pass through scenario (i.e. one where all compliance costs are passed on to consumers), the corresponding increase in consumer prices is expected to be low. Potential cost pass down was found to be highest in the 2026–2030 portion of the analytical period due to front-loading of capital costs, when it amounted to $0.0028/litre (or 0.28′/litre) of gasoline sold, and less than $0.0002/litre (or 0.02′/litre) for diesel and other products. Using 2019 gasoline sales to consumers^{footnote 43} of 1 154 litres per capita nationwide, and 1 512 litres per capita in Saskatchewan, the province with the highest per-capita consumption, the maximum potential impact to consumers was determined to be $3.27 per Canadian per year on average, and $4.29 per person per year in Saskatchewan. It is likely that actual values will be less than these estimates because market competition will prevent industry from passing down all compliance costs.

Sensitivity analysis

Sensitivity analysis allows for the effects of changes in uncertain variables on the outcomes of the Regulations to be factored into the CBA. Partial sensitivity analysis was conducted to examine the impact of key variables on the net benefits of the Regulations, while holding other variables constant. This included both single variable and multiple variable sensitivity analysis. The key variables considered were the discount rate (0%, 3%, 7%), capital costs (+/-20%), and fuel price forecasts (+/-20%). The discount rate accounts for time preferences of consumption (consumption today is preferred to consumption in the future) or time value of money (people prefer to make payments later and receive benefits sooner). Therefore, a higher discount rate would generate lower present value for both benefits and costs, resulting in lower net benefits. While capital costs are part of compliance costs, fuel prices are used to calculate the value of recovered products (production benefits). This means that increasing capital costs would reduce net benefits, while increasing fuel prices would increase net benefits.

As shown in Table 28, changing the capital costs or fuel prices does not alter the conclusion that the Regulations generate net benefits to people in Canada. However, applying a discount rate of greater than 5.4%, without changing any other variables, generates a net cost for the Regulations. Table 29 shows the impact on net benefits when changing multiple variables at a time. The Regulations break even (i.e. generate net benefits close to $0) with a discount rate at 2.5%, capital costs at 20% higher, and fuel prices at 20% lower.

Table 28: Summary results for single variable sensitivity analysis (in millions of 2022 dollars, discounted at 2%)

Variables	Total benefits	Total costs	Net benefits
Central case	1,501.4	1,202.3	299.1
Discount rate at 7%	894.6	980.2	-85.6
Discount rate at 3%	1,342.7	1,149.1	193.6
Discount rate at 0%	1,901.9	1,327.5	574.4
Capital costs at 20% higher	1,501.4	1,383.3	118.1
Capital costs at 20% lower	1,501.4	1,021.4	480.1
Fuel prices at 20% lower	1,431.4	1,202.3	229.1
Fuel prices at 20% higher	1,571.5	1,202.3	369.1

Table 29: Summary results for multiple variable sensitivity analysis scenarios (in millions of 2022 dollars)

Scenario	Variables	Total benefits	Total costs	Net benefits
A	Discount rate at 7%, capital costs by 20% higher and fuel prices at 20% lower	852.9	1,140.7	-287.7
B	Discount rate at 3%, capital costs at 20% higher and fuel prices at 20% lower	1,280.1	1,325.7	-45.6
C	Discount rate at 0%, capital costs at 20% lower and fuel prices at 20% higher	1,990.5	1,137.0	853.5

Small business lens

Analysis under the small business lens concluded that the Regulations will impact small businesses. Based on consultations on the Proposed Approach, it was estimated that three small businesses^{footnote 44} may be affected by the Regulations. Because of the additional bulk plants that were identified through consultations on the Proposed Regulations, it is now estimated that twelve small businesses may be affected by the Regulations.

Equipment requirements of the Regulations are based on a detailed analysis that considers costs, size, scope, health risks and benefits. Lower-cost options were estimated to be within the expected capital and maintenance budgets of the regulated facilities. A cost-effectiveness lens was used to aid in selecting appropriate requirements for various classes of facilities, with an emphasis on minimizing impacts to smaller businesses when risks from emissions are low. Estimates and analysis were based on industry-reported values, vendor quotations, and standard industry practices and methods.

The requirements of the Regulations scale in cost according to the size of a regulated facility and associated equipment. Smaller facilities, including the bulk plants that make up the majority of impacted small businesses, are permitted to use less costly measures such as vapour combustion or vapour balancing. This would still control VOC emission risks and provide more options to meet the requirements of the Regulations. A variable throughput cut-off is used for determining applicability, which reduces or eliminates scope for small facilities posing minimal VOC emissions risks.

The Regulations exclude facilities that store, load and unload volatile petroleum liquids in volumes below a threshold, generally around 2 000 000 standard litres of storage capacity and 4 000 000 standard litres of combined loading and unloading per year, with additional exemptions that increase these thresholds for facilities that are far from buildings and population centres and as a result pose less risk to human health. These exclusion and exemptions mean that the Regulations will not apply to most small businesses engaged in the storage and loading of volatile petroleum liquids.

Small business lens summary

• Number of small businesses impacted: 12
• Number of years: 21 (2025 to 2045)
• Price Year: 2022
• Present value base year: 2024
• Discount rate: 2%

Table 30: Compliance costs

Activity	Annualized value	Present value
Development of inspection program	$264	$4,484
Preparing and submitting repair and outage reports	$255	$4,338
Assisting auditors / enforcement	$37	$626
Total compliance costs	$555	$9,447

Table 31: Administrative costs

Activity	Annualized value	Present value
Familiarization with regulatory obligations	$325	$5,528
Registration	$175	$2,989
Maintaining inspection results	$893	$15,188
Maintaining equipment lists, and substance and throughput records	$1,904	$32,388
Preparing and submitting annual registration update	$792	$13,474
Total administrative costs	$4,089	$69,567

Table 32: Total compliance and administrative costs

Totals	Annualized value	Present value
Total costs (all impacted small businesses)	$4,645	$79,014
Cost per impacted small business	$387	$6,584

One-for-one rule

The one-for-one rule applies since there is an incremental increase in the administrative burden on business as a result of a new regulatory title being introduced. The administrative costs on operators includes costs for testing, monitoring and reporting to demonstrate compliance with the Regulations. Specifically, these include costs for the regulated parties to familiarize themselves with regulatory obligations, generate and submit registration reports, maintain inspection results, maintain equipment lists, substance and throughput records, prepare and submit repair and outage reports, and assist with auditing and enforcement activities. This involves six hours of senior management time (at $61.80/hour in 2012 CAD) in upfront costs (borne in 2025) to become familiar with regulatory obligations, for each refinery, upgrader, chemical facility, and steel facility, and all owners of terminals and bulk plants. Additionally, each regulated facility would require one-time upfront staff time (at $42.96/hour) for facility registration, primarily relating to creation of equipment lists — 40 hours for each refinery, upgrader, and chemical facility, 12 hours for each terminal, 6 hours for each steel facility, and 4 hours for each bulk plant. Lastly, each regulated facility would require staff time each year (at $42.96/hour) to maintain records of inspection results, equipment lists, and substance and throughput records — 56 hours for each refinery, upgrader and chemical facility, 24 hours for each terminal, 12 hours for each steel facility, and 6 hours for each bulk plant. Table 1 provides the number of regulated facilities used in these calculations.

Using 2012 constant dollars, with 2012 as the base year, a 10-year time frame from the year of registration (i.e. 2025 to 2034), and a 7% discount rate, the annualized average increase in the administrative burden on affected businesses is estimated at $165,750 or an average of $344.59 per business, as calculated using the Treasury Board Secretariat of Canada’s Regulatory Cost Calculator tool. This represents an IN under the rule, as per the Policy on Limiting Regulatory Burden on Business.

Regulatory cooperation and alignment

All relevant Canadian policy, including voluntary measures, federal regulations and provincial or municipal measures, were reviewed in detail. Requirements were identified in the provinces of Ontario, Quebec and Newfoundland and Labrador, and the municipalities of Montréal and Metro Vancouver.

Federal regulations in the United States (contained in the U.S. Code of Federal Regulations)^{footnote 45} were reviewed in detail and a scan of individual state requirements was performed.

It was determined that the Regulations align closely with the U.S. policy (the United States has been regulating these emissions sources, using similar requirements, since the 1980s), and also align closely with Canadian provincial and municipal requirements (which largely draw on U.S. requirements and the voluntary CCME codes). The Regulations differ from these requirements in some ways that optimize health risk management, reduce costs to industry and/or update performance requirements, specifically, more stringent requirements for high benzene tanks, equipment size thresholds, considerations for rural and remote facilities, and inspection and repair procedures. Compared with complete alignment, these differences reduce capital and operating costs to industry, while improving protection of human health against benzene exposure. Impacts to other benefits are minimal. The differences are not expected to have any effect on administrative burden or other compliance costs.

Other international policies that generally resembled existing U.S. and Canadian policies were found to exist in other regions, including Europe. These international policies were not investigated in detail because it was determined that the benefit of alignment is small, since international standards are not currently used by industry in Canada and there is no significant integration of petroleum infrastructure or equipment production with countries other than the United States.

There is a requirement to notify the International Maritime Organization that VOC emissions are to be regulated. The requirements of this notification are detailed in regulation 15 of MARPOL Annex VI and must be submitted at least six months before the effective date.

Effects on the environment

The Regulations would result in a reduction in releases of VOCs and benzene to the atmosphere. Reduction in releases of VOCs and improved air quality are expected to contribute to improvements in human health and quality of the environment. There would also be an incidental reduction in GHG emissions, primarily methane emissions reductions.

The VOC emissions reduction is estimated at approximately 494 kt over the analytical period, while the methane emissions reduction is estimated at approximately 8 kt over the analytical period.

The Regulations would directly contribute to the 2022–2026 Federal Sustainable Development Strategy goal to “Improve access to affordable housing, clean air, transportation, parks, and green spaces, as well as cultural heritage in Canada” by reducing emissions of VOCs and benzene (substances with established risk to human health) in and around populated areas and additionally contribute to the Federal Sustainable Development Strategy goal to “Take action on climate change and its impacts” and the United Nations 2030 Agenda for Sustainable Development’s Goal 13 for “Climate action” by reducing emissions of GHGs, primarily methane.

Most of the human health impact of the Regulations is expected to be direct and beneficial, through improved air quality. Any indirect effects on human health and socio-economic conditions from environmental benefits are likely to be small, but also beneficial. No significant negative effects on either human health or the environment were identified.

Gender-based analysis plus

The Regulations will affect over 400 sites across all provinces and territories, including sites located in ports, remote areas and within proximity to urban populations. Workers at these sites, including inspection and maintenance workers, and people living nearby, will be impacted by the Regulations.
The maintenance and inspection practices in the Regulations are well defined and are well aligned with existing practices for inspection and maintenance for this equipment. Therefore, site workers are not expected to be negatively impacted by the Regulations. Operators and inspection and maintenance workers could expect positive health benefits from reduced exposure to carcinogenic substances, including benzene. Overall, workers in the energy sector (including workers at the affected facilities) are mostly adults between 24 and 64 years of age (91%), whereas 24% are female, and 5.7% are Indigenous.^{footnote 46}

Several population groups are particularly susceptible to adverse effects following exposure to ground-level ozone and PM_2.5. These include individuals who are more active outdoors, children, the elderly and individuals with a pre-existing respiratory or cardiac condition. Health risks exist even at low concentration levels of ground-level ozone and PM_2.5; therefore, the Regulations should have positive effects on these groups.

Benzene has been recognized as a human carcinogen. Non-cancer effects from short-term benzene exposure may pose an elevated risk to pregnant women and their developing fetuses. Infants and children may be more affected by benzene concentrations due to differences in breathing rates and body weight. Thus, positive effects from the Regulations are expected on pregnant women and their developing fetuses, as well as infants and children, due to decreased benzene exposure.

Populations living within close proximity to certain sites, especially in densely populated areas, would expect positive health benefits from improved air quality associated with the Regulations. This may include positive impacts to different groups that are particularly vulnerable to adverse effects such as people with lower incomes, elderly people, women (including pregnant women), children and Indigenous Peoples, and positive impacts to people in Canada in general. Specific cases where vulnerable groups were overrepresented among the population near affected sites were identified during the development of the Regulations. At the time of publication, analysis was not available to determine whether vulnerable groups are overrepresented overall in the population of people in Canada living near affected sites.

A healthier environment linked to improvements in air quality and reduced exposure to toxic substances such as benzene as a result of the Regulations will contribute to protecting vulnerable populations from adverse health impacts of air pollution. It will reduce the risk of cumulative effects of certain air pollutants on populations located near facilities covered by the Regulations.

Rationale

VOCs are a precursor pollutant to the formation of ground-level ozone and particulate matter, the main constituents of smog. Exposure to ground-level ozone and particulate matter has harmful effects on human health, causing negative respiratory and cardiac outcomes, and increasing the risk of premature death. Higher levels of ground-level ozone can also reduce crop productivity. Releases of VOCs from storage tanks and loading operations may contain carcinogenic compounds (e.g. benzene) that pose risks to people in the vicinity of these facilities in Canada. In addition, non-cancer effects from short-term benzene exposure may pose an elevated risk to pregnant people and their developing fetuses. Informed by recent ambient air monitoring data, inhalation exposure to evaporative emissions of benzene is of particular concern for populations in some locations with elevated air concentrations.

Fitting storage tanks and loading racks with emissions control equipment combined with robust inspection and maintenance programs are acknowledged as a best practice for controlling evaporative VOC releases from these facilities. Most facilities have fitted many tanks storing volatile petroleum liquids with vapour controls (e.g. floating roofs), and some facilities have fitted loading racks with vapour control systems. These vapour controls are generally based on the voluntary CCME Code and Guidelines, with the focus on reducing VOC releases from tanks and gasoline truck loading. However, significant areas of improvement have been identified, and some tanks and many loading racks remain in operation without these vapour controls in place. Furthermore, even low concentrations of the carcinogens in volatile petroleum liquids can have harmful effects on human health.

The Regulations were developed to address these issues. A broader range of tanks and loading racks will be fitted with more effective vapour controls that minimize VOC releases, and operators would conduct more frequent inspections on floating roofs tanks. These actions will further reduce releases of VOCs, including benzene. Operators will also be required to operate tanks in specific manners and monitor and repair emissions control equipment within specific timelines to minimize VOC releases.

The Regulations are designed to harmonize, where possible, with the regulatory requirements of other jurisdictions, including provinces and the United States. In addition, the Regulations will provide regulatory certainty to the industry and other interested parties, which will create a level playing field and encourage them to plan and invest into the future with confidence.

Implementation, compliance and enforcement, and service standards

Implementation

The Regulations come into force on the day on which they are registered. The implementation of the Regulations follows a phased-in approach, requiring regulated facilities to prioritize highest emitting equipment. Regulated facilities are required to bring a certain percentage of existing storage tanks and loading racks into compliance each year. High benzene tanks are subject to shorter implementation timelines.

Generally, a period of one to three years is permitted to bring equipment into compliance, depending on its prior condition and emissions risk. In cases where a large proportion of existing tanks or loading racks require the installation of emissions control equipment, a period of up to seven years total is allowed for tanks and up to five years total for loading racks.

Interim Order ceases to have effect

Under paragraph 94(7)(b) of CEPA, and pursuant to the notice published in the Canada Gazette, Part I, Volume 158, Number 34 on August 24, 2024^{footnote 47}, the Interim Order (Interim Order Respecting Releases of Benzene from Petrochemical Facilities in Sarnia, Ontario) made by the Minister on May 16, 2024 ceases to have effect on the day on which these Regulations are made.

The Regulations contain provisions to address emissions of benzene that have the same effect as the Interim Order, and these requirements apply to facilities that were subject to the Interim Order immediately when the Regulations come into force.

Compliance

Compliance promotion activities are intended to encourage the regulated community, composed primarily of large enterprises, to achieve compliance. Immediately after publication of the Regulations, and with the coming into force of new requirements in subsequent years, compliance promotion activities will include

• posting of information (e.g. frequently asked questions) on the Department’s website;
• emailing and mailing out notices to interested parties to highlight the dates by which regulated facilities are required to take certain actions (e.g. submitting a registration report);
• arranging conference calls or webinars to review the regulatory requirements and reporting forms with interested parties; and
• providing a guidance document with more details on implementation and compliance.

Once all of the requirements are in force, compliance promotion activities would possibly be limited to responding to and tracking inquiries. Additional compliance promotion may be required if, following an assessment of the promotional activities, compliance with the Regulations is found to be low.

Enforcement

The Regulations are made under CEPA, so enforcement officers would, when verifying compliance with the Regulations once they are in force, apply the Compliance and Enforcement Policy for CEPA.^{footnote 48} That Policy sets out the range of possible responses to alleged violations, including warnings, directions, environmental protection compliance orders, tickets, ministerial orders, injunctions, prosecution and environmental protection alternative measures (which are an alternative to a court prosecution after the laying of charges for a CEPA violation). In addition, the Policy explains when the Department will resort to civil suits by the Crown for cost recovery.

To verify compliance, enforcement officers may carry out an inspection. An inspection may identify an alleged violation, and alleged violations may also be identified by the Department’s technical personnel, or through complaints received from the public. Whenever a possible violation of any regulations is identified, enforcement officers may carry out investigations.

If, following an inspection or an investigation, an enforcement officer discovers an alleged violation, the officer will choose the appropriate enforcement action based on the following factors:

• Nature of the alleged violation: This includes consideration of the damage, the intent of the alleged violator, whether it is a repeat violation and whether an attempt has been made to conceal information or otherwise subvert the objectives and requirements of CEPA;
• Effectiveness in achieving the desired result with the alleged violator: The desired result is compliance within the shortest possible time and with no further repetition of the violation. Factors to be considered include the violator’s history of compliance with CEPA, willingness to cooperate with enforcement officers and evidence of corrective action already taken; and
• Consistency: Enforcement officers will consider how similar situations have been handled in determining the measures to be taken to enforce CEPA.

The Regulations also require concurrent amendments to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999). Those Regulations designate certain provisions in various CEPA regulations that are subject to an increased fine regime following the successful prosecution of an offence involving harm or risk of harm to the environment, or obstruction of authority.

Service standards

The Department, in its administration of the Regulations, will respond to submissions and inquiries from the regulated community in a timely manner taking into account the complexity and completeness of the request. In addition, the Department will develop information sheets and a technical guidance document describing the required information and format to be followed when submitting a plan or report.

Contacts

Magda Little
Director
Oil, Gas and Alternative Energy Division
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: covsecteurpetrolier-vocpetroleumsector@ec.gc.ca

Matthew Watkinson
Executive Director
Regulatory Analysis and Valuation Division
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: ravd-darv@ec.gc.ca