Canada Gazette, Part I, Volume 158, Number 8: Reduction in the Release of Volatile Organic Compounds (Storage and Loading of Volatile Petroleum Liquids) Regulations

February 24, 2024

Statutory authority
Canadian Environmental Protection Act, 1999

Sponsoring departments
Department of the Environment
Department of Health

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 Canadians 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 2} 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 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 3,footnote 4} There is also extensive, robust evidence of adverse health effects associated with exposure to PM_2.5.^{footnote 5} 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 is no risk 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 is a particular concern for agriculture and forestry where economic viability of these industries may be adversely affected.^{footnote 6} 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 the 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 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 7} The National Pollutant Release Inventory reports that Canadian refineries, upgraders, terminals and petrochemical facilities release benzene into the surrounding environment.^{footnote 8} It is expected that releases of carcinogenic substances from these facilities could contribute to cancer risks for Canadians in the vicinity of those facilities.

The Government of Canada’s Screening Assessment – Petroleum Sector Stream Approach: Natural Gas Condensates ^{footnote 9} 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, and a recent report from the Department of Health 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 10} Short-term exposure to elevated benzene levels near gasoline stations may also pose a risk to pregnant people and their developing fetuses.

The analysis of the Department of Environment (the Department) has shown that some communities, including the Aamjiwnaang First Nation near Sarnia, Ontario, may be exposed to elevated ambient levels of benzene that may pose a risk to human health. 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 11} that identified risks to human health, the Department, working jointly with the Department of Health, 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 November 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 commented that further action was needed to address additional sources of VOCs, including the storage and loading of petroleum liquids. The proposed Regulations would address these additional emission sources.

There are federal Regulations that address petroleum storage tanks, the Storage Tanks Systems for Petroleum Products and Allied Petroleum Products Regulations (the amended Regulations),^{footnote 12} promulgated in June 2008 and amended in 2020 to reduce liquid leaks and spills from storage tank systems. These 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 proposed Regulations, including very small storage tanks and tanks that contain non-volatile^{footnote 13} liquids, such as diesel and home fuel oil. The 2008 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 amended 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.

A number of petroleum storage and loading facilities are not covered by voluntary CCME instruments, provincial instruments, or municipal requirements, including many rail, marine, crude oil and petrochemical loading operations. The operating permits for some facilities reference the voluntary CCME guidelines for tanks, however overall compliance with some components, especially the inspection requirements, is low across the sector, based on detailed engagement and discussions to date.

VOC emissions in the upstream petroleum sector^{footnote 14} are regulated under the 2018 Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector). These Regulations do not address VOC emission risks from storage and loading activities at crude terminals or loading activities at oil and gas production sites.

The mixture of aforementioned 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 federal and provincial measures in place. Therefore, there is no consistent standard of protection from the health risks associated with VOC emissions.

Emission sources

Sources of VOC emissions include storage tanks and loading racks at terminals, refineries, upgraders, petrochemical facilities and bulk plants that store large^{footnote 15} quantities of volatile petroleum liquids. According to the Department’s data, total VOC emissions from these facilities were 53 790 tonnes in 2019, with approximately 63% (33 878 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 and inadequate sealing of stored 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 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 16} and primary (refined product) terminals.^{footnote 17} Transport of petroleum to and from these facilities involves multiple modes of transport including pipelines, ships, railcars, and trucks.^{footnote 18} 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 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 19} are located in less densely populated regions where it is uneconomical and impractical to deliver products to end-users from primary terminals.^{footnote 20} 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.

Table 1: Estimated number of facilities by facility type and province/territory

Province/ Territory	Chemical facility	Crude oil terminal	Primary terminal	Refinery	Refinery terminal	Upgrader	Bulk plant	Total	% of total facilities
NL	0	0	5	0	0	0	9	14	5.8
PE	0	0	1	0	0	0	0	1	0.4
NS	0	0	4	0	0	0	1	5	2.1
NB	0	1	3	1	0	0	1	6	2.5
QC	3	3	13	2	1	0	5	27	11.1
ON	7	6	18	5	3	0	22	61	25.1
MB	0	5	2	0	0	0	1	8	3.3
SK	0	16	2	2	0	1	3	24	9.9
AB	3	34	5	5	2	5	7	61	25.1
BC	0	5	19	2	1	0	6	33	13.6
YT	0	0	0	0	0	0	0	0	0.0
NT	0	1	2	0	0	0	0	3	1.2
NU	0	0	0	0	0	0	0	0	0.0
Total	13	71	74	17	7	6	55	243	100.0

Table 2: Estimated VOC emissions from storage and loading operations by facility type and province/territory (tonnes, 2019)

Province/ Territory	Chemical facility	Crude oil terminal	Primary terminal	Refinery	Refinery terminal	Upgrader	Bulk plant	Total
NL	0	0	1 915	0	0	0	9	1 924
PE	0	0	172	0	0	0	0	172
NS	0	0	1 095	0	0	0	25	1 120
NB	0	83	210	1 075	0	0	25	1 392
QC	92	384	1 872	1 076	24	0	29	3 476
ON	355	324	1 055	3 810	18	0	94	5 658
MB	0	427	945	0	0	0	25	1 397
SK	0	2 008	510	1 465	0	634	75	4 692
AB	191	3 847	1 679	1 788	2 001	1 212	176	10 893
BC	0	525	1 787	414	0	0	54	2 781
YT	0	0	0	0	0	0	0	0
NT	0	232	141	0	0	0	0	373
NU	0	0	0	0	0	0	0	0
Total	638	7 829	11 381	9 628	2 043	1 846	513	33 878

Objective

The objectives of the proposed 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 would be achieved.

Description

The proposed Regulations would establish equipment-based requirements^{footnote 21} for new and existing volatile petroleum liquid storage tanks and loading operations at petroleum and petrochemical facilities (hereinafter referred to as “regulated facilities”) located in Canada. Applicability would be facility-specific, and the operator of each regulated facility (hereinafter referred to as “operator”) would be 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 proposed 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 proposed Regulations would follow a phased-in approach, requiring regulated facilities to prioritize highest-emitting equipment. Please see the “Coming into force” subsection for further details.

Sampling and testing

The proposed 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, true vapour pressure, or benzene content. A permitting system would enable the Minister to approve alternatives to these standard methods in cases where the specified methods are not applicable to the liquid being tested; in cases where an operator has identified a method that produces more accurate or precise results; or in cases where an operator wishes to use automated sampling or testing but automation is not supported by the specified methods.

The proposed Regulations would 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 would be required to install, maintain and repair emissions control equipment on petroleum liquid storage tanks and loading racks that handle volatile petroleum liquids, as described in Table 3. The design and operation of this equipment would be subject to standards set out or incorporated by reference in the proposed Regulations.

Table 3: Proposed emissions control equipment requirements

Type of installation	Requirement
Large tanks (greater than 100 m3 internal volume)	Internal floating roof, external floating roof or vapour control system
Small tanks (between 4 m3 and 100 m3 internal volume)	Pressure-vacuum vent
Tanks with internal volumes less than 4 m3	No requirements
Tanks with internal volumes equal to or greater than 4 m3 storing high benzene petroleum liquids (exceeding 20% by weight) or high vapour pressure contents (exceeding 76 kPa true vapour pressure)	Vapour control system table a3 note a
Loading racks	Vapour control system Vapour balancing system permitted at bulk plants
Low-throughput loading racks table a3 note b	No emissions control equipment required
Table a3 note(s) Table a3 note a A permitting system may allow the use of floating roofs for some benzene tanks where exposure risks are low. Return to table a3 note a referrer Table a3 note b A loading rack may qualify as low throughput if the throughputs are below a calculated threshold and the loading rack is at least 300 m from off site buildings. This threshold is dependent on vapour pressure, benzene content and the type of vehicle being loaded, but is generally equivalent to 25 million standard litres of gasoline per year loaded to truck Return to table a3 note b referrer

The proposed Regulations would also set out a permitting system that would allow for the use of alternative emissions control equipment.

Inspections and repairs

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

• Monthly visual inspections of 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 would be required every five years.
• Internal inspection of tanks, including rim seals, every twenty years.
• Annual inspection of pressure-vacuum vents.
• Maintaining a continuous emissions monitoring system on vapour recovery or destruction systems.
• Monthly inspection of vapour control systems for leaks.

Operators would be required to repair defects in emissions control equipment within timelines set out in the proposed Regulations, starting from the date when the defect was discovered. Extended timelines would be permitted under specified circumstances, including cases where the regulated facility already has multiple tanks out of service, 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 would be required when standard repair timelines cannot be met, and development and implementation of an emissions reduction plan would be required whenever cleaning the interior of a tank or replacing the rim seal of an internal or external floating roof tank.

The timeline for floating roof tank repairs would be within 45 days, or up to 180 days if extended timelines apply,^{footnote 22} while that of vapour control system repairs would be within 15 days, or up to 40 days if extended timelines apply. A shorter repair timeline would be required for higher emission risk events where floating roofs have sunk or become flooded. Repair timelines would 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, and they would be extended if the equipment has been fitted with a temporary vapour control system to control emissions.

Record-keeping and reporting

Operators would be 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 would be retained for the lifespan of the equipment, and records relating to inspections performed at intervals longer than six years, which would be retained until the date of next inspection;
• Register regulated facilities with the Department; and
• Submit reports if certain tank and vapour control failures occur, in particular cases where floating roofs have sunk or become flooded, and cases where it was necessary to operate loading equipment for more than 24 hours without a functioning vapour control system.

Scope of coverage

The proposed Regulations would apply to terminals, refineries, upgraders, petrochemical facilities and bulk plants that

• Store volatile petroleum liquids in tanks which meet or exceed a specified capacity, in general 100 m³; or
• Load and unload volatile petroleum liquids that exceed a specified daily or annual quantity, in general 500 000 standard litres per day, or 25 million standard litres per year.^{footnote 23}

A petroleum liquid would be considered to be volatile if it is a liquid at standard conditions (20 °C, 101.325 kPa) and has a true vapour pressure exceeding 10 kPa at these conditions (or actual storage conditions if heated), or exceeding 3.5 kPa if it also contains greater than 2% benzene by weight. By this definition, gasoline, most crude oils, some intermediate products and some petrochemicals would be in scope, while liquids with low VOC emissions such as diesel fuel, kerosene type jet fuel, heating oil and some heavy crudes would not be in scope.

Exemptions for facilities with low emission risks would include

• Facilities 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);
• Offshore facilities located more than 5 km from shore;
• Facilities which only operate tanks with an internal volume of less than 4 m³, vehicle tanks or pressure vessels; and
• Terminals and bulk plants which meet the criteria noted in Table 4.

Table 4: Criteria for additional exempted facilities

Note: Facilities handling liquids with 2% or greater benzene content by weight do not qualify for exemptions.

Facility type	Minimum distance from nearest population centre (km)	Minimum distance from nearest occupied building (m)	Maximum onsite storage capacity (m3)	Maximum annual loading/unloading table a4 note a (m3/year)	Maximum daily loading/unloading table a4 note b (m3/day)
Very small bulk plants	N/A	N/A	500	1 000	N/A
Small bulk plants and terminals	N/A	300	2 000	25 000	500
Small remote terminals or bulk plants	100	N/A	5 000	30 000	2 000
Table a4 note(s) Table a4 note a Includes loading to vehicle tanks (e.g. trucks) and unloading to fixed roof tanks Return to table a4 note a referrer Table a4 note b Includes loading to vehicle tanks (e.g. trucks) and unloading to fixed roof tanks Return to table a4 note b referrer

Coming into force

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

Regulated facilities would be required to bring a certain percentage of existing storage tanks and loading racks into compliance each year. A period of one to three years would be permitted to bring equipment into compliance, depending on its prior condition and emissions risk. Tanks containing liquids with particularly high benzene content (exceeding 20% by weight) would be subject to shorter implementation timelines. At least 80% of tanks at a facility would need to be in compliance within the first three years, and each year the percentage of non-compliant tanks would need to be reduced by 5%. Flexibility would be permitted concerning the timing of compliance with specific requirements relating to seals and fittings on existing floating roofs, where tank inspections demonstrate continued emissions control performance.

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 could be allowed for tanks and up to five years total for loading racks. Regulated facilities would be required to submit an implementation plan and confirm when the facility is in compliance with the proposed Regulations.

Based on this phased-in approach and assuming the proposed Regulations come into force in 2024, it is estimated that most high-emitting loading racks would be fitted with emissions control systems between 2025 and 2027 and most tanks, including all tanks posing the highest benzene emissions risks, would be brought into compliance by the end of 2027. The remaining equipment would be brought into compliance at a rate of over 14% each year until 2031, 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 proposed Regulations

Timeline	Items to comply with proposed 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 Inspections and repairs of existing tanks and loading racks Record-keeping and reporting requirements	N/A
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 two additional years to bring remaining lower emitting loading racks into compliance

Regulatory development

Consultation

Initial consultations — 2021 to 2023

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. At that time, the Department contacted industry representatives, provincial, territorial and municipal governments, Indigenous groups and non-governmental organizations (NGOs) to notify them of the publication of the discussion document and to seek input on the proposed approach. A 60-day informal comment period was initiated, ending in July 2021. Recent consultations with Indigenous communities and interested parties have been undertaken until fall 2023.

In the weeks following the release of the discussion document, the Department conducted English and French webinars providing more detail on the proposed approach; the webinars were attended by a combined 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 after the closure of the formal comment period, holding meetings and telephone calls, and exchanging email correspondence with industry organizations, individual companies, provinces and Indigenous groups, as well as visiting refinery, terminal, and chemical plants and community sites. Points of follow-up discussion included regular updates on the status of the proposed Regulations, discussion of technical details, potential revisions and changes to address concerns, and additional data used to refine either technical requirements or the cost-benefit analysis.

Key comments raised by interested parties addressed implementation and repair timelines, treatment of benzene emission sources, inspection procedures, and coverage of small and/or remote facilities and equipment. The proposed Regulations reflect the feedback received, with key changes from the original version of the proposal, including

• a phased implementation timeline that prioritized highest-risk equipment (i.e. equipment emitting the most VOCs);
• accelerated implementation timelines on sources with a high potential for benzene emissions (i.e. tanks storing liquids with >20% benzene content);
• adjustments to inspection and repair procedures (allowing for longer repair timelines when conditions make it difficult or hazardous to complete repairs quickly, and reduced/modified inspection requirements during winter or other adverse weather conditions); and
• exemption of small facilities in remote areas where they pose a low health risk.

The Department also shared updates on the proposed Regulations during recent meetings on air pollution from the oil and gas sector with First Nation communities and provinces.

Comments received and responses from the Department

Industry

The Department engaged in many discussions with industry representatives from the oil and gas sector, the chemicals sector and other industrial sectors that could be affected by the proposed Regulations, such as the transportation sector. 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 and individual companies operating oil and gas or chemical facilities in Canada. These representatives were supportive of the health and environmental objectives of the draft approach as well as the overall structure proposed (requirements for the use of emissions control equipment combined with requirements for inspection and repair). However, industry representatives expressed concerns with the proposed implementation and repair timelines, citing logistical challenges with fitting emissions control equipment, procurement and supply considerations, as well as a need to remove tanks from service sequentially in order to perform retrofits without disrupting operations. Thus, they sought significantly longer timelines with a phased implementation program.

Industry representatives also sought allowances for reduced or modified inspections during winter or other adverse weather conditions, a larger size threshold for small tanks (in particular, that requirements should apply to tanks over 5 m in diameter rather than the originally proposed 4 m diameter), and raised concerns about the possibility of requirements overlapping or conflicting with other regulated requirements, including provincial regulation and initiatives to reduce methane emissions from the upstream oil and gas sector.

In response to these concerns, the Department included an extended, phased implementation approach in the proposed Regulations. This phased implementation prioritizes the highest-risk emission sources and provides a longer implementation period (seven years for tanks and five years for loading racks, compared to the initial two-year implementation timeline) in cases when large numbers of existing storage tanks or loading racks at a regulated facility need retrofitting or repairs. Provisions were included to accommodate longer repair timelines when conditions make it difficult or hazardous to complete repairs quickly. Adjustments were also made to raise the equipment size at which requirements start to apply, including the size cut-off for small tanks, to reduce the burden on small facilities. A number of technical provisions such as inspection procedures were also adjusted to prevent unnecessary burden and avoid conflict with operational practices.

In response to concerns about the possibility of the proposal overlapping or conflicting with other existing regulated requirements, the Department has made adjustments to facility and equipment applicability as well as equipment and inspection requirements to avoid conflicts and minimize overlap where feasible.

Provincial and territorial governments

Most government representatives who participated indicated support for the proposed Regulations.

All provinces and territories were informed of the proposed Regulations, and some (British Columbia, Saskatchewan, Ontario, Quebec, New Brunswick, and the Northwest Territories) submitted written comments or engaged in discussions with the Department. Overall, representatives who participated indicated support for the proposed Regulations. Some expressed a desire for involvement in the regulatory development process and further discussion on enforcement, data sharing, and interaction with any requirements already in place in their respective jurisdictions.

The Department has engaged further with provincial and territorial partners to discuss the application of the proposed Regulations to activities and emission sources of particular concern, and otherwise ensure the efficacy of the proposed Regulations and minimize the duplication of existing requirements.

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 proposed Regulations includes all locations in Canada where regulated facilities are found, including parts of all provinces and territories except for Nunavut.

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), in particular, in relation to a requirement to consult specified by the JBNQA’s environmental and social protection regime.

To ensure that all potential modern treaty implications are addressed, the bodies responsible for the JBNQA’s environmental and social protection regime will be engaged according to the terms of the Agreement. This engagement will include a review of the proposed Regulations, especially the provisions designed to account for the unique circumstances of northern fuel distribution facilities to ensure that they are sufficient and appropriate to address the needs of the affected Indigenous communities. Provisions that may apply to northern fuel distribution facilities, such as those covered under the JBNQA (in particular, infrequent filling of tanks and limited alternative sources of fuel if equipment is removed from service for maintenance), may result in all facilities covered by the JBNQA falling outside of the scope of the proposed Regulations.

In general, the proposed Regulations are expected to have positive impacts on the treaty rights of modern treaty holders, if any impact exists at all, because they are expected to improve human health and air quality near regulated facilities, and all requirements imposed would be confined to the regulated industrial sites. The Department estimates that the four facilities identified under the JBNQA are below the storage and loading limits and would be excluded from the requirements of this proposal.

Indigenous engagement and consultation

The Department engaged a number of Indigenous groups during the development of the proposed Regulations. Key groups who either submitted written comments or pursued bilateral discussions included the Inuit Tapiriit Kanatami, the Tsleil-Waututh 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 proposed 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.

Representatives from northern areas indicated a need for considerations to ensure that the proposed 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 Department adjusted implementation timelines to ensure that requirements affecting sources with a high potential for benzene emissions come into effect as soon as possible. It also lowered the permissible amount of benzene in vapour control system exhaust. Furthermore, the Department will continue to analyze available information, including monitoring data, to determine whether controls on additional emission sources, such as wastewater treatment and sewers, not addressed by the proposed Regulations, are warranted. In response to concerns related to record-keeping and reporting, the Department has included additional reporting and record-keeping requirements for equipment inventories, repairs and implementation progress and will evaluate options for making reported data publicly available, while protecting confidential business information.

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

Instrument choice

The Department reviewed and assessed various regulatory and non-regulatory instruments to determine the best instrument to achieve the objectives of the proposed 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 acceptance 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 Canadians 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 was not considered as a potential instrument to further reduce VOC releases, as respecting it would be voluntary rather than enforceable. It is not expected that 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, it has been concluded that a code of practice would not result in the reductions of VOC releases that are necessary to adequately protect human health.

Pollution prevention planning notice

A pollution prevention 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 pollution prevention (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 proposed 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 Canadians in the vicinity of the regulated facilities 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) was considered to be an acceptable instrument 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 Tanks Systems for Petroleum Products and Allied Petroleum Products Regulations, to reduce liquid leaks and spills from storage tank systems. The 2008 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 2008 Regulations and the proposed 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 2008 Regulations, instead of establishing new regulations, was also rejected as an option.

New regulations

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 proposed Regulations.

Regulatory analysis

Benefits and costs

Analytical framework

The benefits and costs associated with the proposed Regulations were assessed in accordance with the Treasury Board Secretariat 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 proposed 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 proposed Regulations. The differences in impact between the regulatory scenario and the baseline scenario are the incremental impacts (costs and benefits) of the proposed Regulations. Incremental costs were quantified and monetized. Incremental benefits were quantified and monetized wherever possible; otherwise, they were described qualitatively.

The proposed Regulations would be expected to come into force in 2024 and provide up to seven years for regulated facilities to achieve compliance (e.g. larger facilities, which have more storage tanks, may require more time to bring all of their tanks into compliance). The analytical time frame is 22 years, which begins in 2024 (the year the proposed 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 proposed 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 proposed Regulations establish emissions control measures for new and existing storage tanks and loading operations in the petroleum sector. Compliance with the proposed 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 proposed 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 proposed Regulations. A breakdown of these costs is included in the following logic model.

Figure 1: Logic model for the proposed Regulations

Figure 1: Logic model for the proposed 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, and 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) model was developed to quantify and monetize benefits and costs, and to estimate 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) model were used to determine changes in ambient air concentrations between the two scenarios. The Department of Health’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.

The E3MC, developed by the Department, was used to prepare the baseline air quality data that feeds into the GEM-MACH model. This is an economy-wide model that captures the interactions between the environment and the economy. The 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 generated data on the changes in air pollutant concentrations using the VOC emission reductions estimated by the CBA model. It is a replacement of the former A Unified Regional Air-quality Modelling System, with a detailed representation of atmospheric chemistry and meteorological processes, and a better resolution. 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 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 no noticeable impacts on PM_2.5, sulphur dioxide and nitrogen dioxide.

The AQBAT, a model developed by the Department of Health, 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, the 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 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, whose purpose is to value 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 proposed 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 sum up to the environmental benefits for the proposed Regulations.

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 24} 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/territory	Scope of coverage	Cities	Facility count	Details of coverage
NL	Province-wide	All	14	Vapour control and storage tank design, inspection and maintenance
QC	Province-wide	All	27	Storage tank design
QC	Montréal Municipality	Montréal	7	Vapour control and storage tank design, inspection and maintenance
QC	Montréal Municipality	Montréal-Est	2	Vapour control and storage tank design, inspection and maintenance
ON	Province-wide	All	61	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	124	No provincial or municipal practices
National	n/a	n/a	243	CCME practices

Regulatory scenario

Under the regulatory scenario, all regulated facilities would be 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 would be subject to a phased implementation period of one to seven years. Tanks and loading equipment that enter service after the date of final publication would be immediately subject to all requirements.

Incremental benefits

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

The proposed Regulations would reduce VOC emissions by approximately 494 kt over the analytical period. This reduction would occur 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 proposed Regulations would be a reduction in methane emissions of approximately 8 kt over the analytical period. The reduction in methane emissions is expected to reduce 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 33 878 tonnes annually over the analytical period (2024–2045), following consultations with the industry. However, following implementation of the proposed Regulations, VOC emissions decline to 15 658 tonnes in 2026 and to 8 057 tonnes in 2031, then are constant thereafter due to expected full compliance.

Overall, the proposed Regulations would yield total benefits of approximately $1.43 billion to Canadians and industry over the analytical period, or $87.5 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 proposed Regulations would reduce these specific adverse impacts on the health of people living in Canada, thereby generating health benefits.

Health benefits from reductions of VOC releases

Extensive scientific research in Canada^{footnote 25} 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. The Department of Health’s Air Quality Benefits Assessment Tool (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, the 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 workplace productivity, pain and suffering, and the impacts of changes in mortality risk.

Air quality modelling was undertaken for the year 2031, the year of full implementation for reductions, which begin in 2026. The Department of Health used the modelled air quality results for 2031 to estimate the annual health impacts for each year during the analytical period. Specifically, the Department of Health extrapolated the health impact results from 2031 to the other calendar years, considering changes in population, baseline incidences of disease and mortality, and the estimated VOC emission reductions for each year.

VOC emissions contribute to the formation of secondary PM_2.5 and ground-level ozone in the atmosphere. It is estimated that over the period of analysis, air quality improvements attributed to the proposed 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. The total present value of health benefits resulting from these air quality improvements is estimated at $1.05 billion (2022 Canadian dollars) for the analytical period.

As shown in Table 7, aggregate health benefits from the proposed Regulations would be most significant in British Columbia, Quebec, Alberta, and Ontario. 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 remoter 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 the Department of Health’s model (AQBAT), including nitrogen dioxide.

Table 7: Cumulative health benefits (reduction in adverse health outcomes and economic benefits) associated with air quality improvements (2024–2045)

Province	Reduction in premature deaths (number)	Reduction in asthma symptom days in asthmatics aged 5 to 19	Reduction in days of restricted activity in non-asthmatics	Economic health benefits from reduction in PM2.5 (in millions of 2022 dollars, discounted at 2%)	Health benefits from reduction in annual and summer ground-level ozone (in millions of 2022 dollars, discounted at 2%)	Total health benefits from reduction in all pollutants (in millions of 2022 dollars, discounted at 2%)
QC	42	7 800	23 000	155.1	144.5	302.5
ON	24	5 200	12 000	66.7	100.5	167.4
AB	31	8 600	26 000	134.6	89.3	223.9
BC	39	7 900	23 000	130.4	148.6	281.4
Other	10	1 900	7 000	48.8	25	73.9
Canada	150	31 000	91 000	535.5	507.9	1,049.0

Figures may not add up to totals due to rounding.

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 26}

Health benefits from reduced VOC releases from bulk plants

In addition to the monetized health benefits estimated using the AQBAT, the proposed Regulations are expected to reduce VOC emissions from bulk plants, estimated at about 8 kt in total. However, locations of these bulk plants are not known, and therefore their emission reductions were not included in the modelling of air quality impacts (health and environmental impacts). It is expected that a reduction of VOC emissions from bulk plants would result in additional local air quality improvements.

Health benefits of reductions in carcinogenic substances

The proposed Regulations would reduce emissions of toxic substances such as benzene, a known human carcinogen. The Department of Health 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.

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 proposed Regulations would reduce associated economic costs for the agri-food and forestry industries and therefore result in environmental benefits.

Using the AQVM2, the Department estimated the environmental impacts of air quality improvements on soiling, visibility and crop productivity associated with the proposed Regulations, based on the comparison of the baseline scenario versus the policy scenario. 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, the year of full implementation for reductions that begin in 2026. The Department used the modelled air quality results for 2031 to estimate the annual impacts for each year during the analytical period. Specifically, the environmental impacts were extrapolated from 2031 to the other calendar years, considering changes in population and the estimated VOC emission reductions for each year.

The total present value of environmental benefits resulting from air quality improvements attributable to the proposed Regulations is estimated at $14.2 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 (2024–2045, in millions of 2022 dollars, discounted at 2%)

Province/Territory	Soiling/Avoided costs for households	Visibility/Change in welfare for households	Crop productivity/Change in sales revenues for crop producers	Total
NL	0	0.02	0	0.02
PE	0	0.04	0	0.05
NS	0.03	0.14	0	0.18
NB	0	0.02	0	0.03
QC	0.59	1.68	0.42	2.68
ON	0.24	0.13	1.64	2.01
MB	0.15	0.32	0.18	0.65
SK	0.08	0.17	0.41	0.65
AB	1.47	3.05	0.50	5.03
BC	0.94	1.93	0	2.88
YT	0	0	0	0
NT	0	0	0	0
NU	0	0	0	0
Canada	3.52	7.49	3.18	14.19

Note: Figures may not add up to totals due to rounding. Benefit estimates below $10,000 are presented as "0".

Over the analytical period, avoided household cleaning costs of about $3.5 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 27}Welfare gains from improved visibility in the residential sector are approximately $7.5 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 $3.2 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. However, due to data and/or methodological limitations, these benefits have not been quantified by the AQVM2.

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 proposed Regulations. Table 9 and Table 10 provide the volume estimates of the recovered products.

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

Province/Territory	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0	11 400	11 400	11 400	11 400	45 602
PE	0	1 028	1 028	1 028	1 028	4 110
NS	0	3 689	5 096	5 096	5 096	18 977
NB	0	1 368	5 038	5 038	5 038	16 481
QC	0	10 059	12 049	12 049	12 049	46 206
ON	0	8 595	21 403	21 403	21 403	72 803
MB	0	3 261	4 661	4 661	4 661	17 243
SK	0	5 395	10 246	10 246	10 246	36 132
AB	0	22 419	30 632	30 632	30 632	114 314
BC	0	8 635	10 487	10 487	10 487	40 096
YT	0	0	0	0	0	0
NT	0	559	559	559	559	2 236
NU	0	0	0	0	0	0
Canada	0	76 407	112 598	112 598	112 598	414 202

Note: Figures may not add up to totals due to rounding.

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

Province/Territory	2024–2025	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	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	76	76	76	291
AB	0	97	141	141	141	521
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	184	261	261	261	968

Note: Figures may not add up to totals due to rounding.

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 28} 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 were assumed constant over the years.

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

Province/Territory	2024–2025	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	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045
Canada-heavy crude	62.41	62.41	62.41	62.41	62.41
Canada-light crude	76.99	76.99	76.99	76.99	76.99
Canada-average	69.70	69.70	69.70	69.70	69.70

The production benefits from recovered crude oil was estimated at $53 million, while that of recovered gasoline was estimated at $289 million over the analytical period, for a total of $343 million in recovered products (Table 13).

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

Province/territory	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0	9.6	8.9	8.1	7.4	33.9
PE	0	0.8	0.7	0.7	0.6	2.8
NS	0	2.7	3.5	3.2	2.9	12.2
NB	0	1.1	3.7	3.4	3.1	11.2
QC	0	8.4	9.6	8.8	8.0	34.7
ON	0	6.6	15.3	14.0	12.8	48.7
MB	0	2.6	3.6	3.3	3.0	12.4
SK	0	8.3	12.1	11.0	10.0	41.3
AB	0	23.6	30.2	27.5	25.1	106.4
BC	0	9.1	10.0	9.2	8.4	36.6
YT	0	0	0	0	0	0
NT	0	0.6	0.6	0.5	0.5	2.1
NU	0	0	0	0	0	0
Canada	0	73.3	98.1	89.5	81.6	342.5

Note: Figures may not add up to totals due to rounding.

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 greenhouse gas that contributes to global warming. Climate change benefits from reduction of methane emissions were calculated using the social cost of methane. The first step involved estimating the annual reductions in methane emissions attributable to the proposed 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 reduction in methane emissions.

The proposed Regulations would reduce methane emissions by approximately 8 kt over the analytical period, resulting in climate change benefits (reduced climate change damages) of $24.3 million.

14: Estimated reduction in methane emissions (kilotonnes)

Province/territory	2024–2025	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

Note: Figures may not add up to totals due to rounding.

Incremental costs

Overall, the proposed Regulations would impose a total cost of approximately $1.09 billion to the industry and the Government over the analytical period, or $67 million annualized. Below is a breakdown of the cost components.

Industry costs

In order to comply with the proposed Regulations, the industry would have to carry capital and operating costs (compliance costs). In addition, in order to demonstrate compliance with the proposed Regulations, the industry would also have to carry testing, monitoring, and reporting costs (administrative costs). The total costs to the industry are estimated at $1.08 billion over the analytical period.

Capital costs

The proposed 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 would bear 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 would be given two to seven years to install emissions control equipment.

Main tank capital costs associated with the proposed 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 29} Likewise, major loading operations capital costs associated with the proposed 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 30}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)
Tanks	Perform complete replacement of floating roof seal (26 m diameter tank)	Gasoline / crude oil	$516,556
	Retrofit fixed roof tank with new internal floating roof (26 m diameter tank)	Gasoline	$885,524
	Retrofit vapour control unit on high benzene internal floating roof tank	Benzene	$5,088,811
	Install vapour balancing system at bulk plant	Gasoline	$241,084
Loading racks	Vapour control system at small truck/rail terminal (< 150 000 m3/year)	Gasoline / crude oil	$2,361,397
	Vapour recovery system at medium truck/rail terminal (< 450 000 m3/year)	Gasoline / crude oil	$4,014,375
	Vapour recovery system at large truck/rail terminal (> 450 000 m3/year)	Gasoline / crude oil	$8,737,169
	Marine loading vapour recovery system (approximatively 1 500 000 m3/year)	Gasoline / crude oil	$13,637,068

The estimated total capital costs for installing emission control equipment on tanks and loading operations are approximately $828 million from 2026 to 2030 (see Table 16), with a significant portion, around $695 million, expected to be assumed 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 $330 million, while installation of this equipment in loading operations is expected to cost $498 million.

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

Province/territory	Cost related to emission control equipment on storage tanks	Cost related to emission control equipment on loading racks	Total cost
NL	2.5	17.0	19.4
PE	0.5	3.9	4.4
NS	1.7	26.3	28.0
NB	6.7	4.8	11.4
QC	37.7	97.9	135.6
ON	84.5	62.2	146.7
MB	12.5	28.4	40.9
SK	37.2	52.2	89.5
AB	116.0	99.2	215.2
BC	28.0	90.5	118.5
YT	0	0	0
NT	2.8	15.4	18.2
NU	0	0	0
Canada	330.1	497.7	827.9

Note: Figures may not add up to totals due to rounding.

Operating costs

The proposed Regulations would require the industry to regularly inspect and repair their storage tanks, loading racks and emission control equipment. Lower explosive level testing would be required for internal floating roof tanks, and seal gap inspection would be required for external floating roof tanks. These operating costs are expected to start in 2026 as regulated facilities would be given two 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 would be 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
Tanks	Lower explosive level and visual inspection of internal floating roof at a site with 15 to 20 tanks	Gasoline/crude oil	$22,669
Tanks	Vapour control system on tank	Benzene	$100,832
Tanks	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
Loading racks	Vapour recovery unit at medium truck/rail terminal (< 450,000 m3/yr)	Gasoline/crude oil	$100,832
Loading racks	Vapour recovery unit at large truck/rail terminal (> 450,000 m3/yr)	Gasoline/crude oil	$106,735
Loading racks	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
  • 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 and visual inspections on internal floating roofs
• Inspection intervals for loading racks:
  • 1-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 $247 million over the analytical period (Table 18).^{footnote 31} 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 $103 million (Table 19), while the same costs for loading operations are estimated at $144 million (Table 20).

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

Province or territory	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0.0	0.9	1.0	0.9	0.8	3.7
PE	0.0	0.4	0.4	0.4	0.4	1.6
NS	0.0	1.7	1.9	1.8	1.6	7.0
NB	0.0	1.2	1.4	1.3	1.2	5.0
QC	0.0	8.7	10.0	9.1	8.2	36.0
ON	0.0	8.5	11.2	10.1	9.2	39.0
MB	0.0	3.4	4.1	3.7	3.4	14.5
SK	0.0	7.8	9.7	8.8	7.9	34.2
AB	0.0	15.8	21.1	19.1	17.3	73.4
BC	0.0	6.7	8.0	7.3	6.6	28.6
YT	0.0	0.0	0.0	0.0	0.0	0.0
NT	0.0	0.9	1.1	1.0	0.9	4.0
NU	0.0	0.0	0.0	0.0	0.0	0.0
Canada	0.0	55.9	70.1	63.5	57.5	247.0

Note: Figures may not add up to totals due to rounding.

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

Province or territory	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0.0	0.1	0.0	0.0	0.0	0.2
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	24.9
MB	0.0	0.8	1.2	1.1	1.0	4.0
SK	0.0	2.2	3.3	3.0	2.7	11.3
AB	0.0	7.5	11.6	10.5	9.5	39.2
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	21.0	30.1	27.3	24.7	103.1

Note: Figures may not add up to totals due to rounding.

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

Province or territory	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
NL	0.0	0.8	1.0	0.9	0.8	3.5
PE	0.0	0.4	0.4	0.4	0.3	1.5
NS	0.0	1.6	1.8	1.7	1.5	6.6
NB	0.0	0.7	0.8	0.8	0.7	3.0
QC	0.0	5.4	6.2	5.6	5.0	22.1
ON	0.0	3.4	3.9	3.5	3.2	14.1
MB	0.0	2.6	2.9	2.7	2.4	10.5
SK	0.0	5.6	6.4	5.8	5.2	22.9
AB	0.0	8.3	9.5	8.6	7.8	34.2
BC	0.0	5.3	6.1	5.5	5.0	22.0
YT	0.0	0.0	0.0	0.0	0.0	0.0
NT	0.0	0.8	0.9	0.9	0.8	3.4
NU	0.0	0.0	0.0	0.0	0.0	0.0
Canada	0.0	34.9	40.0	36.2	32.8	143.9

Note: Figures may not add up to totals due to rounding.

Other compliance costs

Other compliance costs, not categorized as capital or operational costs in the previous sections, would amount to $2.8 million over the analytical period. This includes an upfront cost of $0.6 million for the regulated parties to establish an inspection program and ongoing costs of $2.2 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	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
Upfront	595,682	0	0	0	0	595,682
Development of inspection program	595,682	0	0	0	0	595,682
Ongoing	220,715	571,955	518,038	469,203	424,971	2,204,882
Assisting auditors/enforcement	220,715	515,015	466,465	422,492	382,664	2,007,351
Preparing and submitting repair and outage reports	0	56,940	51,573	46,711	42,307	197,531
Total	816,397	571,955	518,038	469,203	424,971	2,800,564

Administrative costs

The proposed Regulations are expected to result in around $5.9 million in incremental administrative costs to industry over the analytical period. This includes one-time costs of less than $0.1 million for the regulated parties to familiarize themselves with regulatory obligations and to produce and submit registration reports. It also includes annual ongoing costs of about $5.9 million over the analytical period for 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	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045	Total
Upfront	63,253	0	0	0	0	63,253
Familiarization with regulatory obligations	37,312	0	0	0	0	37,312
Registration	25,941	0	0	0	0	25,941
Ongoing	646,923	1,509,527	1,367,225	1,238,338	1,121,601	5,883,615
Maintaining inspection results	323,461	754,764	683,613	619,169	560,801	2,941,808
Maintaining equipment lists and substance and throughput records	323,461	754,764	683,613	619,169	560,801	2,941,808
Total	710,176	1,509,527	1,367,225	1,238,338	1,121,601	5,946,868

Government costs

The proposed Regulations would result in program administration, compliance promotion, and enforcement costs for the federal government. The total government costs are estimated at approximately $10 million over the analytical period.

Program administration

Program administration is pivotal in the implementation and management of the proposed Regulations. Key activities include keeping web content up to date, processing and analyzing reports from operators, measuring program performance, and overseeing permit approvals and maintenance under the proposed Regulations’ optional permitting systems. Notably, these systems offer permits for using floating roofs as an alternative to vapour control systems for certain tanks containing liquids with high benzene content; permits for novel alternative emissions control equipment; and permits for alternative testing methods to determine substance properties. Total program administration costs are estimated at approximately $4.6 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. These include developing, posting and distributing promotional materials such as frequently asked questions and fact sheets, holding information sessions, responding to information or clarification requests, tracking inquiries, sending reminder letters, advertising in trade and association magazines, and attending trade association conferences. Compliance promotion activities are expected to be minimal, as operators comprise only of large enterprises that have the resources and capacity to develop a good understanding of their legal obligations on their own. These costs would 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 proposed Regulations would 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 bear enforcement costs of $4.4 million over the analytical period. This includes a one-time cost of $0.65 million for training enforcement officers and undertaking strategic intelligence assessment work. It also includes total recurring costs of $3.75 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 $1.43 billion, while the costs are estimated to be around $1.09 billion. The net benefits of the proposed Regulations are estimated to be about $337 million.

The benefits analysis shows that the proposed Regulations would generate $1.05 billion in health benefits and $14 million in environmental benefits. Other benefits include $343 million in production benefits from recovered products and $24 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 would bear compliance costs of about $1.08 billion to implement the proposed regulatory requirements. This would include $828 million in capital costs, $247 million in operating costs, and $2.8 million in other compliance costs. In addition, the industry and the government would bear administrative costs of nearly $6 million and $10 million, respectively.

• Number of years: 22 (2024 to 2045)
• Base year for costing: 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	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045	Total	Annualized value
Canadians	Health benefits	0.0	226.3	270.2	275.4	277.2	1,049.0	59.4
	Environmental benefits	0.0	3.3	3.8	3.6	3.4	14.2	0.8
	Climate change benefits	0.0	4.9	6.2	6.5	6.8	24.3	1.4
Industry	Production benefits	0.0	73.3	98.1	89.5	81.6	342.5	19.4
All parties	Total benefits	0.0	307.7	378.3	375.0	369.0	1,430.0	81.0

Note: Figures may not add up to totals due to rounding.

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

Impacted parties	Description of cost	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045	Total	Annualized value
Industry	Capital costs	0.0	827.9	0.0	0.0	0.0	827.9	46.9
	Operating costs	0.0	55.9	70.1	63.5	57.5	247.0	14.0
	Other compliance costs	0.8	0.6	0.5	0.5	0.4	2.8	0.2
	Administrative costs	0.7	1.5	1.4	1.2	1.1	5.9	0.3
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	0.0
	Enforcement	1.1	1.0	0.9	0.8	0.7	4.4	0.2
All interested parties	Total costs	3.2	888.2	74.1	67.1	60.8	1,093.5	61.9

Note: Figures may not add up to totals due to rounding.

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

All interested parties	2024–2025	2026–2030	2031–2035	2036–2040	2041–2045	Total	Annualized value
Total benefits	0.0	307.7	378.3	375.0	369.0	1,430.0	81.0
Total costs	3.2	888.2	74.1	67.1	60.8	1,093.5	61.9
Net impact (benefits-costs)	-3.2	-580.5	304.2	307.9	308.2	336.5	19.1

Note: Figures may not add up to totals due to rounding.

Quantified (non-monetized) and qualitative impacts

• Health and environmental benefits from air quality improvements attributable to reduced VOC releases from bulk plants (VOC emission reductions quantified but not monetized)
• Health benefits of reductions in exposure 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 Table 27.

Within the provinces, Alberta, Ontario, Quebec, British Columbia, and Saskatchewan would make up 85.3% of compliance costs. The same provinces would also account for 80.4% of VOC emission reductions. 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 32}

Among the various types of regulated facility, primary terminals, crude oil terminals, and refineries account for 83.7% of compliance costs. Likewise, the same facility types combined account for 85% 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/territory

Province or territory	Total compliance costs ($million)	Total compliance costs (%)	Total VOC emission reductions (kt)	Total VOC emission reductions (%)
NL	23.1	2.2	34.2	6.9
PE	5.9	0.6	3.1	0.6
NS	35.0	3.3	17.8	3.6
NB	16.5	1.5	17.3	3.5
QC	171.6	16.0	44.7	9.1
ON	185.8	17.3	64.5	13.1
MB	55.4	5.2	22.3	4.5
SK	123.7	11.5	73.2	14.8
AB	288.5	26.8	170.7	34.6
BC	147.1	13.7	43.6	8.8
YT	0.0	0.0	0.0	0.0
NT	22.1	2.1	2.3	0.5
NU	0.0	0.0	0.0	0.0
Canada	1,074.9	100	493.6	100

Note: Percentages may not add up to 100% due to rounding.

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	391.1	36.4	178.0	36.1
Crude oil terminal	329.7	30.7	126.8	25.7
Refinery	178.6	16.6	114.9	23.3
Refinery terminal	64.4	6.0	36.3	7.4
Chemical facility	59.6	5.5	8.6	1.7
Upgrader	43.8	4.1	21.3	4.3
Bulk plant	7.6	0.7	7.7	1.6
Total	1,074.9	100	493.6	100

Note: Percentages may not add up to 100% due to rounding.

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 tanks at refineries. It is projected to bear most of the total regulatory costs, approximately 58%.
• Crude oil: This includes upgraders and most crude tanks/terminals, which are expected to incur 37% 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 $741 million. These costs are expected to be mostly incurred within the first five years following the implementation of the proposed 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 around 50% 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 or 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 product loading operations, 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 proposed 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 stated above, compliance industry costs represent a relatively modest fraction of the annual operating expenditures (or falls with the annual variation of capital expenditures of the affected facilities).

The degree to which production cost may be passed on to consumers 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 33} 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 $0.0025/litre (or 0.25¢/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 34} of 1 153 litres per capita nationwide, and 1 783 litres per capita in Saskatchewan, the province with the highest per-capita consumption, the maximum potential impact to consumers was determined to be $2.85 per person per year on average, and $4.40 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 proposed Regulations to be factored into the CBA. Two types of analysis were conducted, partial sensitivity analysis and Monte Carlo analysis.

Partial sensitivity analysis was conducted to examine the impact of key variables on the net benefits of the proposed 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 proposed Regulations generate net benefits to Canadians. However, applying a discount rate of greater than 6.3%, without changing any other variables, generates a net cost for the proposed Regulations. The proposed Regulations break even (i.e. generate net benefits close to $0) with a discount rate at 3.4%, capital costs at 20% higher, and fuel prices at 20% lower.

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

Variables	Total benefits	Total costs	Net benefits
Central case	1,430.0	1,093.5	336.5
Discount rate at 7%	851.4	898.4	-47.0
Discount rate at 3%	1,278.6	1,046.8	231.8
Discount rate at 0%	1,812.0	1,203.1	608.9
Capital costs at 20% higher	1,430.0	1,259.1	170.9
Capital costs at 20% lower	1,430.0	927.9	502.1
Fuel prices at 20% lower	1,361.5	1,093.5	268.0
Fuel prices at 20% higher	1,498.5	1,093.5	405.0
Discount rate at 7%, capital costs by 20% higher and fuel prices at 20% lower	810.7	1,046.2	-235.6
Discount rate at 3%, capital costs at 20% higher and fuel prices at 20% lower	1,217.4	1,208.6	8.8
Discount rate at 0%, capital costs at 20% lower and fuel prices at 20% higher	1,898.7	1,029.4	869.3

Monte Carlo analysis was also conducted to jointly assess the sensitivity of the three key variables (discount rate, capital costs, and fuel prices). Monte Carlo analysis uses computer-based simulation to perform repeated random sampling of key variables that are identified as being subject to uncertainty. This process generates expected values and statistical probabilities. Thus, one can see the likelihood of the outcome (such as net benefits) occurring when all variables of interest are allowed to vary simultaneously. This simulation had 10 000 iterations, each generating an expected value of the net benefit. Triangular distribution was assumed for the discount rate (0% minimum, 2% modal, 7% maximum) while pert distribution was assumed for changes in capital costs and fuel prices (-20% minimum, 0% most likely, 20% maximum). The results of Monte Carlo analysis showed that the proposed Regulations would result in an average net benefit of $249 million, with a 90% likelihood that the net benefit would be between $5 million and $509 million. As well, there would be a 95% chance that the proposed Regulations would at least result in a net benefit to Canadians and a 5% chance of a net cost.

Small business lens

Analysis under the small business lens concluded that the proposed Regulations would impact small businesses. Based on consultations on the discussion document of the proposed approach, it is estimated that three small businesses^{footnote 35} may be affected by the proposed Regulations. Additional analysis may be required if more small businesses are identified during Canada Gazette consultations.

Equipment requirements of the proposed 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 proposed Regulations scale in cost according to the size of a regulated facility and associated equipment. Smaller facilities would be 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 proposed 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 proposed 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 20 000 000 standard litres of combined loading and unloading per year. These exclusions would mean that the proposed Regulations would 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: 3
• Number of years: 22 (2024 to 2045)
• Base year for costing: 2022
• Present value base year: 2024
• Discount rate: 2%

Table 29: Compliance costs

Activity	Annualized value	Present value
Development of inspection program	$363	$6,405
Preparing and submitting repair and outage reports	$1,281	$22,621
Assisting auditors / enforcement	$64	$1,127
Total compliance costs	$1,708	$30,153

Table 30: Administrative costs

Activity	Annualized value	Present value
Registration	$18	$320
Maintaining inspection results	$1,922	$33,931
Maintaining equipment lists, and substance and throughput records	$1,922	$33,931
Total administrative costs	$3,862	$68,182

Table 31: Total compliance and administrative costs

Totals	Annualized value	Present value
Total costs (all impacted small businesses)	$5,569	$98,335
Cost per impacted small business	$1,856	$32,778

One-for-one rule

The one-for-one rule applies since there would be an incremental increase in the administrative burden on business as a result of a new regulatory title being introduced. The administrative costs on operators would include costs for testing, monitoring and reporting to demonstrate compliance with the proposed Regulations. Specifically, these would 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 would involve six hours of senior management time (at $61.80/hour) in upfront costs (borne in 2024) to become familiar with regulatory obligations, for each refinery, upgrader, chemical facility and all owners of terminals, marine terminals, and bulk plants. Additionally, each regulated facility would require 2 hours of staff time (at $42.96/hour) in upfront costs for facility registration. Lastly, each regulated facility would require 24 hours of staff time (at $42.96/hour) — or 32 hours of staff time for refineries, upgraders and chemical facilities — every year to maintain records of inspection results, equipment lists, and substance and throughput records. 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. 2024 to 2033), and a 7% discount rate, the annualized average increase in the administrative burden on affected businesses is estimated at $119,963 or an average of $416,54 per business, as calculated using the Treasury Board Secretariat’s Regulatorry 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 36} were reviewed in detail and a scan of individual state requirements was performed. Informal discussion with the U.S. Environmental Protection Agency representatives indicated there were no concerns regarding the proposed Regulations.

It was determined that the proposed 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 proposed 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 liquid tanks, equipment size thresholds, considerations for rural and remote facilities, and inspection and repair procedures.

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 would be 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.

Discussions with Transport Canada highlighted 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.

Strategic environmental assessment

The proposed Regulations would result in a reduction in releases of VOCs and benzene to the atmosphere. Reductions 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 emission 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 proposed 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 proposal 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

This proposal may affect over 700 sites across all provinces and territories (except Nunavut), including sites located in ports, remote areas and within proximity to urban populations. Preliminary analysis indicates that workers at these sites, including inspection and maintenance workers and peoples living nearby, would be impacted by this proposal.

The maintenance and inspection practices for this proposal 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 proposal. Operators and inspection and maintenance workers could expect positive health benefits from this proposal 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 37}

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 proposal 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 proposal 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 this proposal. This may include positive impacts to different groups that are particularly vulnerable to adverse effects such as lower-income Canadians, elderly Canadians, women (including pregnant women), children and Indigenous Peoples, and positive impacts to Canadians in general. Specific cases where vulnerable groups were overrepresented among the population near affected sites were identified during the development of the proposed Regulations. At the time of publication, analysis was not available to determine whether vulnerable groups are overrepresented overall in the population of Canadians 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 this proposal would contribute to protecting vulnerable populations from adverse health impacts of air pollution. It would reduce the risk of cumulative effects of certain air pollutants on populations located near facilities covered by this proposal.

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 Canadians in the vicinity of these facilities. 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 proposed Regulations were developed to address these issues. A broader range of tanks and loading racks would be fitted with more effective vapour controls that minimize VOC releases, and operators would conduct more frequent inspections on floating roofs tanks. These actions would further reduce releases of VOCs, including benzene. Operators would also be required to operate tanks in specific manners and monitor and repair emissions control equipment within specific timelines to minimize VOC releases.

The proposed Regulations are designed to harmonize, where possible, with the regulatory requirements of other jurisdictions, including provinces and the United States. In addition, the proposed Regulations would provide regulatory certainty to the industry and other interested parties, which would 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 proposed Regulations would come into force on the day on which they are registered. The implementation of the proposed Regulations would follow a phased-in approach, requiring regulated facilities to prioritize highest emitting equipment. Regulated facilities would be required to bring a certain percentage of existing storage tanks and loading racks into compliance each year. Tanks containing liquids with particularly high benzene content (exceeding 20% by weight) would be subject to shorter implementation timelines.

Generally, a period of one to three years would be 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 could be allowed for tanks and up to five years total for loading racks.

The final Regulations are expected to be published in the Canada Gazette, Part II, in 2024.^{footnote 38}

Compliance promotion

Compliance promotion activities are intended to encourage the regulated community, composed solely 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 could include

• posting of information (e.g. frequently asked questions) on the Department website;
• emailing and mailing out notices to interested parties to highlight the dates by which regulated facilities would be required to take certain actions (e.g. submitting an annual report);
• arranging conference calls or webinars to review the regulatory requirements and reporting forms with interested parties;
• responding to information or clarification requests; 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 proposed Regulations would be 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 39} 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 proposed 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 proposed Regulations, would 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 intends to develop information sheets and/or 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
Email: covsecteurpetrolier-vocpetroleumsector@ec.gc.ca

Matthew Watkinson
Executive Director
Regulatory Analysis and Valuation Division
Environment and Climate Change Canada
Email: ravd-darv@ec.gc.ca

PROPOSED REGULATORY TEXT

Notice is given, under subsection 332(1)^{footnote a} of the Canadian Environmental Protection Act, 1999 ^{footnote b}, that the Governor in Council proposes to make the annexed Reduction in the Release of Volatile Organic Compounds (Storage and Loading of Volatile Petroleum Liquids) Regulations under subsection 93(1)^{footnote c}, section 286.1^{footnote d} and subsection 330(3.2)^{footnote e} of that Act.

Any person may, within 60 days after the date of publication of this notice, file with the Minister of the Environment comments with respect to the proposed Regulations or a notice of objection requesting that a board of review be established under section 333^{footnote f} of that Act and stating the reasons for the objection. Persons filing comments are strongly encouraged to use the online commenting feature that is available on the Canada Gazette website. Persons filing comments by any other means, and persons filing a notice of objection, should cite the Canada Gazette, Part I, and the date of publication of this notice, and send the comments or notice of objection to Magda Little, Director, Oil, Gas and Alternative Energy, Energy and Transportation Directorate, Environmental Protection Branch, Department of the Environment, 351 Saint-Joseph Boulevard, Gatineau, Quebec K1A 0H3 (email: covsecteurpetrolier-vocpetroleumsector@ec.gc.ca).

A person who provides information to the Minister may submit with the information a request for confidentiality under section 313^{footnote g} of that Act.

Ottawa, February 19, 2024

Wendy Nixon
Assistant Clerk of the Privy Council

TABLE OF PROVISIONS

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

Interpretation

1 Definitions

Application

• 2 Non-application — facilities
• 3 Non-application — equipment

General Provisions

In Service

• 4 Tank
• 5 Intermittent service tanks
• 6 Vapour control system

Designation

• 7 Tanks
• 8 Loading racks
• 9 Designation process
• 10 Existing tanks

Equipment Identification

11 Identifier

Internal Volume of a Tank

12 Internal volume

Requirements for Sampling and Testing

Properties of Liquids

• 13 Immiscible phases
• 14 Gasoline

Methods for Sampling Liquids

• 15 Sampling of crude oil and other
• 16 Qualified professional

Test Methods

• 17 True Vapour Pressure
• 18 Benzene concentration
• 19 VOC concentrations — liquids
• 20 VOC concentrations — vapour
• 21 Combustible gas detector — requirements
• 22 Qualified professional

Alternative Test Methods

• 23 Application to the Minister
• 24 Rejection of application
• 25 Approval of application
• 26 Begin use of method
• 27 Publication of approved alternative methods

Requirements for VOC Emissions Control

Emissions Control Equipment

• 28 Emissions control equipment
• 29 Required training

Tanks

• 30 Emissions control equipment
• 31 Vapour control system
• 32 Volatile petroleum liquid tank
• 33 Small volatile petroleum liquid tank
• 34 Position of liquid inlet

Loading Racks

• 35 Vapour control systems
• 36 Position of liquid inlet

Existing High Benzene Tanks — Permit

• 37 Application for permit
• 38 Conditions for issuing permit
• 39 Revocation of permit

Design and Operation of Emissions Control Equipment

Vapour Control Systems — Gasoline Loading — Trucks

40 Standard

Vapour Control Systems — General Requirements

• 41 Design specifications
• 42 Design, operation and maintenance
• 43 Continuous monitoring device
• 44 Standard operating procedures
• 45 Continuous operation
• 46 Scheduled maintenance
• 47 Performance — emissions
• 48 Performance — existing systems
• 49 Temporary vapour control system
• 50 Free of leaks
• 51 Compatible fittings

Internal Floating Roofs

• 52 Installation
• 53 Float on surface of the liquid
• 54 Remaining afloat
• 55 Exposed seams
• 56 Continuous vapour-tight enclosure
• 57 Gap between seal and wall of tank
• 58 Openings
• 59 Rims
• 60 Materials

External Floating Roofs

• 61 Installation
• 62 Float on surface of the liquid
• 63 Remaining afloat
• 64 Exposed seams
• 65 Continuous vapour-tight enclosure
• 66 Gap between seal and wall of tank
• 67 Openings
• 68 Rims
• 69 Materials

Pressure-Vacuum Vents

• 70 Requirements
• 71 Ventilation

Alternative Emissions Control Equipment

• 72 Application for permit
• 73 Issuance
• 74 Conditions of the permit
• 75 Additional information
• 76 Revocation

Requirements for Inspection, Testing and Repair

Vapour Control Systems

Inspection and Tests

• 77 Inspection — every 30 days
• 78 Performance test — defects
• 79 Performance test — modifications
• 80 Vapour balancing system — test
• 81 Records

Repair

82 Repair — deadline

Internal Floating Roofs and External Floating Roofs

Inspection of Internal Floating Roof

• 83 Every 30 days
• 84 Inspection
• 85 Baseline LEL%
• 86 Inspection — every 20 years

Inspection of External Floating Roof

• 87 Every 30 days
• 88 Annual inspection
• 89 Inspection — every five years
• 90 Inspection — every 20 years
• 91 Seal replacement measurement
• 92 Inspector Certificate
• 93 Records

Other requirements

• 94 Reduced inspection intervals
• 95 Report to Minister

Inspections of Existing Tanks Performed Before the Coming into Force of These Regulations

• 96 Inspection period
• 97 Defects

Repair

• 98 Repair — tank not in service
• 99 Repair — tank in service

VOC Emissions Reduction Plan

100 Cleaning tank or replacing seal

Pressure-Vacuum Vent

Inspection

101 Pressure-vacuum vent

Repair

102 Defect detected

Extended Repair Plan

103 Reasons

Inventory

104 Inventory

Record-Keeping

Records

• 105 Tanks
• 106 Loading racks
• 107 Measurements and calculations
• 108 Training completed
• 109 Minister’s request — records

Retention of Records

110 Six years

Registration of Facility

111 Report of registration

Delayed Application — Existing Tanks and Loading Racks

Delay

• 112 Floating roofs
• 113 First anniversary — existing tanks
• 114 Third anniversary — existing tanks

Additional Period of Delayed Application

• 115 Designation
• 116 Fourth year — tanks
• 117 Fifth year — tanks
• 118 Sixth year — tanks
• 119 Seventh year — tanks
• 120 Eighth year — no tanks
• 121 Consequential Amendment to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999)

Coming into Force

122 Registration

SCHEDULE 1

Control Conditions

1

Procedure

2

SCHEDULE 2

Control Conditions

1

Procedure

2

SCHEDULE 3

Total Loading Factor

1

Total Daily Loading Factor

2

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.

ASTM

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

design specifications

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

emissions control equipment

means any type of equipment, including a vapour control system or floating roof, that is used to limit VOC emissions from tanks and loading racks. (équipement de contrôle des émissions)

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 participate 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 line to property line distance of no more than 5 km. (installation)

fixed roof

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

floating roof

means a structure that floats on and is supported by 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; 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, and
  • (iv) a distillation temperature at which 50% of the fuel has evaporated of not less than 60°C and not greater than 120°C. (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 tank

means a tank that is designated under paragraph 7(a). (réservoir de liquide à haute concentration en benzène)

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. (fuite de liquide)

loading

means any transfer of a liquid during which vapours could be displaced from the receiving vessel, including a transfer of volatile petroleum liquid into a vehicle tank or fixed roof tank, but does not include a transfer of a volatile petroleum liquid into a floating roof tank or pipeline or a transfer of fuel into a vehicle’s fuel 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 equipment, piping and instrumentation used for the loading of volatile petroleum liquids. (rampe de chargement)

lower explosive limit percentage or LEL%

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

lower explosive limit (LEL) or LEL

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

operator

, in respect of a facility, means the person who operates, has charge of, manages or controls the facility. (exploitant)

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 a social or community centre, including a mobile home or portable building but does not include other mobile structures such as a tent, trailer or houseboat. (bâtiment occupé)

petroleum

means all naturally occurring hydrocarbons such as natural gas, natural gas condensate, crude oil or bitumen, hydrocarbon derivatives of those substances, such as fuels, lubricating oils, petrochemicals or asphalt, and their synthetic or semi-synthetic analogues. (pétrole)

petroleum processing equipment

means equipment that is used to physically or chemically separate, transform or modify petroleum, including equipment such as a distillation column, reactor or coker, but does not include equipment used only for storing, handling or blending petroleum, such as a pump, tank 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 release of gas to the environment in the event of excess pressure or vacuum inside of a fixed roof tank. (évent de pression dépression)

primary seal

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

qualified professional

means a scientist or technologist who specializes in an applied science or technology applicable to the duty or function, such as engineering, engineering technology or chemistry, and is registered with the appropriate professional organization. (professionnel qualifié)

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)

tank

means a tank, vessel, reservoir or container that is used to contain liquids, regardless of its shape or material of construction. (réservoir)

true vapour pressure or TVP

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 réelle ou PVR)

vapour

means any type of vapour or gas containing VOCs, including vapours 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 captures all vapours emitted from tanks or during loading operations and prevents them from being released to the environment, including a vapour recovery system, a vapour destruction system or a vapour balancing system. (système de contrôle des vapeurs)

vapour destruction system

means a vapour control system that destroys vapours by combustion, thermal oxidation or other means. (système de destruction des vapeurs)

vapour leak

means any release of vapour other than a release for which a portable monitoring instrument is used to determine that the concentration of VOCs at the source is 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 recovery system

means a vapour control system that captures vapours for use. (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 as a permanent stationary liquid storage site. (véhicule)

vehicle tank

means a tank attached to or integrated into a vehicle, including a fuel tank. (réservoir de véhicule)

volatile organic compound or VOC

means a compound that participates in atmospheric photochemical reactions and that is not excluded under item 60 of Part 2 of Schedule 1 to the Canadian Environmental Protection Act, 1999. (composé organique volatil ou COV)

volatile petroleum liquid

means petroleum or a petroleum 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 of volatile organic compounds by weight; and
• (c) has a TVP greater than 10 kPa, or has a TVP greater than 3.5 kPa if the benzene concentration is greater than 2% 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

Non-application — facilities

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

• (a) facilities where petroleum liquids are stored or loaded exclusively for the purposes of retail fuel sales at that facility;
• (b) upstream oil and gas facilities, as defined in subsection 2(1) of the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector), except for
  • (i) facilities that separate natural gas liquids into its individual components or fractions,
  • (ii) oil sands facilities, as defined in subsection 2(1) of the Multi-Sector Air Pollutants Regulations, and
  • (iii) facilities where crude oil or condensate is received by pipeline, truck, rail or marine transfer, stored in tanks and then distributed by pipeline, truck, rail or marine transfer, except for facilities that directly receive effluents extracted from wells for the purpose of separation and measurement of petroleum liquids such as crude oil or condensate;
• (c) offshore facilities that are located more than 5 km from shore;
• (d) facilities whose property line is located more than 100 km from any population centre, provided that
  • (i) the loading racks at the facility never load volatile petroleum liquids with a benzene concentration greater than 1% 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 5000 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;
• (e) 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, provided that
  • (i) the tanks at the facility never store and the loading racks at the facility never load volatile petroleum liquids with a TVP greater than 76 kPa or a benzene concentration greater than 1% by weight,
  • (ii) the sum of the internal volume of all tanks at the facility 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;
• (f) facilities where the following conditions are met:
  • (i) the tanks at the facility never store and the loading racks at the facility never load volatile petroleum liquids with a TVP greater than 76 kPa or a benzene concentration greater than 1% by weight,
  • (ii) the sum of the internal volume of all tanks at the facility used to store volatile petroleum liquids is less than 500 m³, and
  • (iii) the total volume of volatile petroleum liquid loaded at the facility does not exceed 1000 standard m³ in a calendar year; and
• (g) facilities that use only the tanks and loading racks referred to in paragraphs 3(1)(a) to (c) and only the vessels referred to in subsection 3(2).

Upgrading facilities — application

(2) For greater certainty, these Regulations apply to facilities that engage in the upgrading – by means involving distillation – of crude oil or bitumen, or of blends of crude oil or bitumen with other hydrocarbon compounds.

Distance of occupied building

(3) For the purposes of these Regulations, the distance between a tank or loading rack and an occupied building is the minimum distance between any point on the perimeter of the tank or loading rack and any point on the perimeter of the occupied building.

Non-application — equipment

3 (1) These Regulations apply to all tanks and loading racks at a facility except for

• (a) tanks with an internal volume of less than 4 m³;
• (b) vehicle tanks; and
• (c) 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.

Pressure vessels

(2) These Regulations do not apply to pressure vessels that operate without releases to the environment during normal operating conditions, including during filling and emptying of the vessel and during changes in ambient conditions.

General Provisions

In Service

Tanks

4 (1) A tank is considered to be in service beginning on the day on which it first contains a volatile petroleum liquid.

Does not contain volatile petroleum liquid

(2) Despite subsection (1), a tank is considered to not contain a volatile petroleum liquid if

• (a) the tank has been cleaned to remove a volatile petroleum liquid, vapour, any sludge and any solid petroleum materials and the value of the LEL% inside the tank is less than 10 without the use of mechanical ventilation; or
• (b) a liquid other than a volatile petroleum liquid has been introduced into the tank and
  • (i) sampling 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 without the use of mechanical ventilation.

Tank not in service

(3) A tank is considered to not be in service when it does not contain a volatile petroleum liquid.

Intermittent service tanks

5 (1) The operator may designate no more than three tanks at a single facility as intermittent service tanks if those tanks will be in service for less than 300 hours in a calendar year and if those tanks are designated as belonging to a category referred to in paragraph 7(c) or (d).

Variation in properties

(2) 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, a statistical or engineering analysis must be conducted to demonstrate that the tank is expected to be in service for less than 300 hours in a calendar year before the tank is designated as an intermittent service tank.

Exempt from requirements

(3) A tank that has been designated as an intermittent service tank is exempt from the emissions control requirements set out in sections 32 and 33.

Notice to Minister — 30 days

(4) The operator must notify the Minister at least 30 days before the day on which the operator designates a tank as an intermittent service tank unless the designation is made within one year after the day on which these Regulations come into force, in which case no notification is required under this subsection.

Vapour control system

6 A vapour control system is considered to be in service beginning on the day on which it is first used at the facility.

Designation

Tanks

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

• (a) as a high benzene tank, in which case the tank may contain any volatile petroleum liquid;
• (b) as a high volatility liquid tank, in which case the tank may contain a volatile petroleum liquid only if the benzene concentration of that liquid does not exceed 20% by weight;
• (c) as a volatile petroleum liquid tank, in which case the tank may contain a volatile petroleum liquid only if the TVP of that liquid does not exceed 76 kPa and its benzene concentration does not exceed 20% by weight; or
• (d) as a small volatile petroleum liquid tank, in which case the tank
  • (i) must have an internal volume of less than 100 m³ and, 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 contain a volatile petroleum liquid only if the TVP of that liquid does not exceed 76 kPa and its benzene concentration does not exceed 20% by weight.

Loading racks

8 (1) The operator 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) as a high benzene loading rack, in which case the loading rack may be used to load any volatile petroleum liquid;
• (b) as a volatile petroleum liquid loading rack, in which case the loading rack may be used to load a volatile petroleum liquid only if the benzene concentration of that liquid does not exceed 20% by weight; or
• (c) as a low throughput loading rack, in which case the loading rack may be used to load a volatile petroleum liquid only if the benzene concentration of that liquid does not exceed 20% by weight and either if
  • (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 if:
    • (A) the total loading factor of the facility calculated according to the method set out in section 1 of Schedule 3 does not exceed 1, and
    • (B) the total daily loading factor of the facility calculated in accordance with the method set out in section 2 of Schedule 3 does not exceed 1, or
  • (ii) the loading rack is located more than 100 km from any population centre and more than 2 km from any occupied building and if
    • (A) the total loading factor of the facility calculated in accordance with the method set out in section 1 of Schedule 3 does not exceed 2, and
    • (B) the total daily loading factor of the facility calculated in accordance with the method set out in section 2 of Schedule 3 does not exceed 2.

Low throughput loading rack

(2) A loading rack that is designated as a low throughput loading rack under paragraph (1)(c) is exempt from the emissions control requirements set out in section 35.

Designation process

9 The operator must designate the category of a tank or loading rack by updating the inventory established under section 104 and indicating the category in the records maintained under sections 105 and 106.

Existing tanks

10 (1) A tank that is in service before the day on which these Regulations come into force and that is designated under section 7 within one year after the day on which these Regulations come into force is considered to be an existing tank.

Existing loading racks

(2) A loading rack that is used to load a volatile petroleum liquid before the day on which these Regulations come into force and that is designated under subsection 8(1) within one year after the day on which these Regulations come into force is considered to be an existing loading rack.

Existing vapour control systems

(3) A vapour control system that is in service at the facility before the day on which these Regulations come into force is considered to be an existing vapour control system.

Equipment Identification

Identifier

11 (1) The operator must ensure that each tank, loading rack and vapour control system at the facility is assigned an identifier.

Marking on equipment

(2) The identifier must be marked on the tank, loading rack or vapour control system or indicated on a site plan such that each tank, loading rack or vapour control system can be identified at any time.

Records, requests, notices and reports

(3) The identifier must be included in all records that relate to the tank, loading rack or vapour control system and in all requests, notices and reports with respect to the tank, loading rack, or vapour control system that are submitted to the Minister under these Regulations.

Internal Volume of a Tank

Internal volume

12 (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.

Sealed spaces

(2) The volume of any space that has been sealed to prevent the entry of vapour or liquid, including the space above an internal floating roof, is not included in the calculation of the internal volume of a tank.

Connected tanks

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

Tank with separate compartments

(4) If a compartment of a tank is sealed to prevent entry of vapour or 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

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

Requirements for Sampling and Testing

Properties of Liquids

Immiscible phases

13 (1) For the purposes of these Regulations, the VOC concentration, the TVP or the benzene concentration of a liquid with multiple immiscible phases is the highest value of the VOC concentration, the TVP or the 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 for the purposes of the determination:

• (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

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

Methods for Sampling Liquids

Sampling of crude oil and other

15 (1) 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 gas or vapour under ambient conditions must be performed in accordance with the method set out in the standard ASTM D3700–21, entitled Standard Practice for Obtaining LPG Samples Using a Floating Piston Cylinder.

Insufficient pressure

(2) Despite subsection (1), if the pressure at the sampling point is insufficient to permit sample collection, the sampling must be performed in accordance with 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.

Liquid too viscous

(3) Despite subsections (1) and (2), if the liquid is too viscous to permit the use of one of the methods referred to in those subsections, the sampling must be performed in accordance with the method set out in standard ASTM D4057–22, entitled Standard Practice for Manual Sampling of Petroleum and Petroleum Products.

Other liquids

(4) The sampling of liquids other than those referred to in subsection (1) must be performed in accordance with one of the sampling methods referred to in subsections (1) to (3).

Sample containers

(5) 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

16 The sampling of liquids and vapours must be performed by a qualified professional who has, not more than 12 months before the first time that they perform sampling, received training relevant to the performance of sampling and training on the relevant requirements of these Regulations.

Test Methods

True Vapour Pressure

17 (1) The TVP of any liquid must be determined in accordance with one of the following test methods:

• (a) the method ASTM D2879–18, 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).

Vapour-liquid ratio

(2) A vapour-liquid ratio of 0.1 must be used to determine the TVP of a liquid in accordance with the test method referred to in paragraph (1)(b).

Temperature

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

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

Benzene concentration

18 The benzene concentration of a liquid is to be determined in accordance with one of the following test methods:

• (a) the method ASTM D3606–21, entitled Standard Test Method for Determination of Benzene and Toluene in Spark Ignition Fuels by Gas Chromatography;
• (b) the method ASTM D4367–02, 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 Napthas 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 Gasoline 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 D7504–21, 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

19 The VOC concentration in liquids is to 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.

VOC concentrations — vapour

20 (1) An instrument used to determine the presence of VOCs in gas or 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 5(3) of the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector); or
• (c) a combustible gas detector that uses a catalytic bead sensor and meets the requirements set out in section 21 of these Regulations.

Instruments — LEL%

(2) An instrument used to determine the 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 gas or vapour is a vapour leak must be of the type referred to in paragraph (1)(a).

Equivalent VOC concentration

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

Records

(5) The operator must maintain records that contain the following information and any supporting documents in respect of each instrument at the facility:

• (a) the design specifications for the instrument; and
• (b) the results of each calibration or test performed on the instrument, the date when it was performed and the name of the person who performed it.

Combustible gas detector — requirements

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

• (a) it is calibrated each day before it is used in accordance with its design specifications, with a calibration gas and, if necessary, output correction factors, appropriate for the expected gas or vapour composition;
• (b) it produces an output directly in units of LEL%;
• (c) it has an output range that spans at least 1 LEL% to 100 LEL%; and
• (d) it has an output accuracy that is within plus or minus 5% of a reading or plus or minus 2 LEL%, whichever value is greater, when used with the expected gas or 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 is likely to poison the catalyst; or
• (c) any other environment in which, according to the design specifications of the combustible gas detector, may not provide an accurate output.

Qualified professional

22 The testing of liquids and vapours must be performed by a qualified professional who has, not more than 12 months before the first time they perform testing, received training relevant to the performance of testing and training on the relevant requirements of these Regulations.

Alternative Test Methods

Application to the Minister

23 (1) The operator may apply to the Minister to use an alternative test method to those required under sections 17 to 19 in order to:

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

Conditions — alternative test method

(2) The alternative test method must:

• (a) measure the same physical properties as one of the test methods required under sections 17 to 19; 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 17 to 19.

Time limit

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

Information

(4) The application must contain the following information:

• (a) the purposes for which the operator wishes to use an alternative test method under subsection (1);
• (b) evidence that the conditions set out in subsection (2) are met;
• (c) the name of the alternative test method and its description; and
• (d) a description of the circumstances in which the alternative test method would be used, including any limitations or restrictions on when it would be used.

Equivalency of method

(5) For the purpose of paragraph (4)(b), the operator must, in accordance with one of the following test methods, evaluate the equivalency of the alternative method to the test methods required under sections 17 to 19:

• (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 D6708–21, 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.

Rejection of application

24 If the Minister determines that the alternative test method is not equivalent to the test methods required under sections 17 to 19, the Minister must reject the application. The Minister must notify the operator of that conclusion in writing.

Approval of application

25 If the Minister determines that the alternative test method is equivalent to the test methods required under sections 17 to 19, the Minister may accept the alternative test method and must notify the operator of the decision in writing.

Begin use of method

26 The operator may begin using the alternative test method on receipt of the notice of approval by the Minister.

Publication of approved alternative methods

27 (1) The Minister may publish a list of approved alternative test methods, including the situations in which their use is appropriate.

Use of approved alternative test method

(2) The operator may use an 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 approved alternative test method have been met.

Requirements for VOC Emissions Control

Emissions Control Equipment

Emissions control equipment

28 (1) The operator must ensure that tanks designated under section 7 and loading racks designated under subsection 8(1), that are at the facility are equipped with emissions control equipment in accordance with the requirements set out in sections 31 to 36, 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 40 to 71 and the requirements with respect to inspection, testing and repair set out in sections 77 to 103, as applicable.

Required training

29 The operator must ensure that the emissions control equipment 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 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.

Tanks

Emissions control equipment

30 The operator 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

31 Subject to section 37, the operator must ensure that each high benzene tank and each tank designated as a high volatility liquid tank under paragraph 7(b), are each equipped with a vapour control system.

Volatile petroleum liquid tank

32 The operator must ensure that each tank at the facility that is designated as a volatile petroleum liquid tank under paragraph 7(c) is equipped with at least one of the following:

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

Small volatile petroleum liquid tank

33 The operator must ensure that each tank at the facility that is designated as a small volatile petroleum liquid tank under paragraph 7(d) is equipped with at least one of the following:

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

Position of liquid inlet

34 The liquid inlet of a tank must be 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

35 The operator must ensure that each loading rack at the facility that is designated as a high benzene loading rack under paragraph 8(1)(a) and as a volatile petroleum liquid loading rack under paragraph 8(1)((b) is equipped with one of the following vapour control systems:

• (a) in the case of a loading rack at a facility where fuel is stored either in fixed roof tanks that are each less than 5 m diameter and 100 m³ in volume or in underground tanks of any size, a vapour recovery system, a vapour destruction system or a vapour balancing system;
• (b) in the case of a gasoline loading rack that is used for trucks at a facility where more than 250 000 standard m³ per year of gasoline is loaded per year and was not already equipped with an existing vapour destruction system on the day on which these Regulations came into force, a vapour recovery system; and
• (c) in any other case, a vapour recovery system or a vapour destruction system.

Position of liquid inlet

36 The liquid inlet to any vehicle tanks receiving volatile petroleum liquids from a loading rack is positioned such that liquid enters the tank no more than 15 cm above the bottom of the tank.

Existing High Benzene Tanks — Permit

Application for permit

37 (1) The operator may apply to the Minister for a permit to use an internal floating roof instead of a vapour control system to control VOC emissions from any existing high benzene tank at their facility that satisfies all of the following criteria at the time of the application:

• (a) the tank is located more than 300 m from any occupied building;
• (b) the tank is equipped with an internal floating roof that was installed before the day on which these Regulations come into force; and
• (c) the tank is equipped with an internal floating roof that meets the requirements in sections 52 to 60 and that is free from the defects referred to in subsections 99(5) and (6).

Deadline

(2) The permit application must be made no later than 180 days after the day on which these Regulations come into force.

Condition — fenceline monitoring program

(3) The operator may apply for a permit only if, at the time of the application, the operator has established and maintained one of the following fenceline monitoring programs at the facility:

• (a) a standard fenceline monitoring program in accordance with the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector);
• (b) a modified fenceline monitoring program in accordance with the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector);
• (c) an alternative fenceline monitoring program in accordance with the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector);
• (d) 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
• (e) a fenceline monitoring program that meets all the requirements of the method published by the United States Environmental Protection Agency entitled 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 of another document entitled Method 325B — Volatile Organic Compounds from Fugitive and Area Sources: Sampler Preparation and Analysis, and all samples must be analyzed for benzene.

Information

(4) The permit application must contain the following information:

• (a) the unique identifier of each existing high benzene tank at the facility and an indication of which tanks the operator is seeking to include in the permit;
• (b) a copy of all records maintained under section 105 for each existing high benzene tank at the facility;
• (c) a map or site plan that indicates the exact location of each existing high benzene tank at the facility;
• (d) a description, including dates and locations, of any events that are likely to have significantly affected ambient benzene levels at or near the facility within the previous 24 months, including changes in operating processes, changes in emissions control measures and accidental releases;
• (e) a description, including dates and locations, of any events that are likely to occur within the next 12 months that may significantly affect future ambient benzene levels at or near the facility, including expected changes in operating processes or emissions control measures;
• (f) a description of the fenceline monitoring program established and maintained in accordance with subsection (3), including
  • (i) the type of program established, among those referred to in paragraphs 3(a) to (e),
  • (ii) 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,
  • (iii) the number of sampling tubes and their location at the fenceline, and a description of the analysis used to determine that number and those locations, including the method used, the factors taken into account and the calculations, if any, carried out in the course of the analysis, and
  • (iv) a diagram of the facility that includes the property boundary, fenceline, sampling locations, petroleum processing equipment, tanks, loading racks and wastewater treatment areas; and
• (g) all monitoring data from the fenceline monitoring program established and maintained in accordance with subsection (3), including the concentration of benzene for each sampling period at each sampling location, as well as the concentration of benzene in each field blank and duplicate sample, in respect of the following periods:
  • (i) in the case of a facility that has maintained a fenceline monitoring program for at least 38 months before the day on which the application is made, a continuous period of 36 months ending no earlier than 60 days before the day on which the application is made, or
  • (ii) in the case of a facility that has maintained a fenceline monitoring program for less than 38 months before the day on which the application is made, a continuous period beginning at the earliest time when data is available and no later than 60 days after the day on which these Regulations come into force and ending no earlier than 60 days before the day on which the application is made.

Conditions for issuing permit

38 (1) The Minister may issue a permit if, at every sampling location of the fenceline monitoring program, both of the following conditions are met:

• (a) the benzene concentrations measured in at least 24 of the 26 most recent sampling periods were below the following values:
  • (i) in the case of a sampling period that ends before the day on which these Regulations come into force or during the first year after the day on which these Regulations come into force, 19 µg/m³,
  • (ii) in the case of a sampling period that ends during the second year after the day on which these Regulations come into force, 17 µg/m³,
  • (iii) in the case of a sampling period that ends during the third year after the day on which these Regulations come into force, 15 µg/m³, or
  • (iv) in the case of a sampling period that ends during the fourth year after the day on which these Regulations come into force or during any subsequent years, 13 µg/m³; and
• (b) the arithmetic average of the benzene concentrations measured for the 26 most recent sampling periods was below the following values:
  • (i) if the most recent sampling period ends before the day on which these Regulations come into force or during the first year after the day on which these Regulations come into force, 6.5 µg/m³,
  • (ii) if the most recent sampling period ends during the second year after the day on which these Regulations come into force, 5.5 µg/m³,
  • (iii) if the most recent sampling period ends during the third year after the day on which these Regulations come into force, 4.5 µg/m³, or
  • (iv) if the most recent sampling period ends during the fourth year after the day on which these Regulations come into force or during any subsequent years, 3.5 µg/m³.

Permit

(2) The issued permit must set out its period of validity and indicate which existing high benzene tanks at the facility may be equipped with an internal floating roof instead of a vapour control system to control VOC emissions.

Notice — no permit issued

(3) If the conditions referred to in subsection (1) are not met, the Minister must not issue the permit and must notify the operator in writing to that effect and provide them with an opportunity to make written representations concerning the refusal.

Update of information to maintain permit

(4) For the purposes of maintaining the validity of the permit, the permit holder must provide the Minister with the information set out for each of the following periods within the time indicated for each:

• (a) annually, within 30 days after the anniversary of the date on which the permit is effective,
  • (i) an update of the information referred to in paragraphs 37(4)(a) to (f), and
  • (ii) an update of the fenceline monitoring data referred to in paragraph 37(4)(g) including the most recent available data;
• (b) within 30 days after the day on which the permit holder receives data that would establish that the conditions referred to in subsection (1) are no longer met, an update of the fenceline monitoring data referred to in paragraph 37(4)(g) including the most recent available data; and
• (c) within 30 days after the day on which an inspection is carried out, the results of any inspection of the tanks to which the permit applies during which a defect referred to in subsection 99(5) or (6) is detected.

Revocation of permit

39 (1) The Minister must revoke the permit if the conditions for issuing the permit that are set out in subsection 38(1) are no longer met.

Modification of permit

(2) The Minister may modify the permit to exclude a tank if the tank no longer meets the criteria set out in subsection 37(1).

Benzene emissions

(3) The Minister may modify the permit to exclude a tank or revoke the permit if the Minister determines that the revocation or modification will reduce benzene emissions at the facility.

Use after revocation or modification

(4) After the permit is revoked or modified, the Minister may allow the permit holder to continue to use internal floating roofs instead of vapour control systems for the following periods:

• (a) if the revocation or modification relates to no more than two tanks, a period of up to one year; or
• (b) if the revocation or modification relates to three or more tanks, a period of no more than six months multiplied by the number of tanks.

Temporary vapour control system

(5) The Minister may allow the permit holder to continue to use an internal floating roof instead of a vapour control system if the permit holder installs a temporary vapour control system referred to in subsection 49(1) on the tank before the date specified by the Minister.

Unrelated release of benzene

(6) Despite subsections (1) and 38(3), the Minister may issue or maintain a permit if the Minister determines that the conditions set out in subsection 38(1) were not met due to a release of benzene at the facility that is unrelated to the existing high benzene tanks at the facility, or a release of benzene outside the facility.

Notice of modification or revocation

(7) The Minister must notify the permit holder in writing with written reasons of any revocation or modification of the permit at least 30 days before the day on which a modification or revocation takes effect and provide the permit holder with an opportunity to make written representations concerning the modification or the revocation.

Design and Operation of Emissions Control Equipment

Vapour Control Systems — Gasoline Loading — Trucks

Standard

40 The operator must ensure that the requirements of the National Standard of Canada CAN/CGSB-3.1000-2019, 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 trucks loading gasoline.

Vapour Control Systems — General Requirements

Design specifications

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

Design, operation and maintenance

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

• (a) collect all vapours discharged from the tank or loading rack 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 in section 48 for the full range of inlet vapour flow rates and VOC concentrations; and
• (c) minimize the accumulation of liquid within the vapour piping.

Continuous monitoring device

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

• (a) generates an accurate measurement that indicates VOC capture or destruction, either by directly measuring VOC vapour concentration in the exhaust gas or by measuring other physical parameters such as combustor temperature;
• (b) alerts the operator if VOC capture or destruction does not meet the performance requirements in section 48; and
• (c) operates at all times when the vapour control 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; or
• (b) measures temperature with an accuracy of plus or minus 2°C.

Standard operating procedures

44 The operator must, for each vapour control system, 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 in accordance with the requirements of these Regulations.

Continuous operation

45 (1) The operator must ensure that the vapour control system operates continuously during all periods when the tank is in service or when the loading rack is being used to load volatile petroleum liquids.

Maintenance and repair

(2) Despite subsection (1), the operation of the vapour control system may be interrupted for a period of maintenance or repair of not more than 5% of the periods in a calendar year when the tank is in service or when the loading rack is being used to load volatile petroleum liquids.

Report to the Minister

(3) If the period of maintenance or repair of the vapour control system is a continuous period of more than 24 hours and the use of the tank or the loading rack is needed during that period, the operator must, within five days after the day on which the maintenance or repair has begun, submit a report to the Minister and it must include the following information:

• (a) a description of the vapour control system, including its identifier;
• (b) a description of the maintenance or repair activity;
• (c) the expected period during which the vapour control system will be inoperative; and
• (d) a description of any measures that will be taken to reduce VOC emissions during the period of maintenance or repair.

Report update

(4) The operator must update the report required under subsection (3) within five days after the day on which the maintenance and repair of the vapour control system has been completed and the system has returned to normal operation.

Scheduled maintenance

46 When the vapour control system is not in operation during a period of maintenance that is not the result of an unexpected failure of the vapour control system, VOC emissions must be controlled by

• (a) in the case of a tank, a temporary vapour control system; and
• (b) in the case of a loading rack
  • (i) a temporary vapour control system, or
  • (ii) limiting loading so that the facility’s total daily loading factor, as calculated in accordance with the method set out in section 2 of Schedule 3, is less than 1 in a day, or, if the facility does not load volatile petroleum liquids with a benzene concentration greater than 1% by weight, so that the total throughput of volatile petroleum liquids is less than 500 standard m³ each day.

Performance — emissions

47 (1) At all times during its operation, a vapour recovery system or vapour destruction system must 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 and the following requirements must be met:

• (a) if the system is a thermal oxidizer, the gas in the system must be maintained at a temperature of at least 760^oC for a residence time of at least 0.75 seconds;
• (b) if the system is a catalytic oxidizer, the gas in the system must be maintained at a temperature of at least 400^oC; and
• (c) if the system is a vapour destruction system, the NO_x emission intensity must not exceed 50 g NO_x per GJ of the total VOCs and supplemental fuel provided to the flare, quantified on a higher heating value 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 vapour recovery system or vapour destruction system must not emit more than 10 mg of VOCs per m³ of vapour vented or 10 mg of VOCs per standard m³ of volatile petroleum liquid loaded.

Performance — existing systems

48 (1) Despite subsection 47(1), at all times during its operation, an existing vapour recovery system or vapour destruction system must 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 and the following requirements must be met:

• (a) if the system is a thermal oxidizer, the gas in the system must be maintained at a temperature of at least 760^oC for a residence time of at least 0.75 seconds; and
• (b) if the system is a catalytic oxidizer, the gas in the system must be maintained at a temperature of at least 400^oC.

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 existing vapour recovery system or vapour destruction system must not emit more than 50 mg of VOCs per m³ of vapour vented or 50 mg of VOCs per standard m³ of volatile petroleum liquid loaded .

Temporary vapour control system

49 (1) The operator may use a temporary vapour control system on a tank or loading rack at a facility for a period not exceeding 135 days or for one of the applicable periods referred to in subsection 39(4).

Requirements

(2) The temporary vapour control system must be a vapour recovery system or vapour destruction system and must meet the performance requirements for existing systems that are set out in section 48 and all other requirements for vapour control systems under these Regulations.

Exception — openings

(3) Despite subsection (2), subsection 50(2) does not apply to a temporary vapour control system that has been fitted to a tank equipped with an internal floating roof.

Free of leaks

50 (1) The operator must ensure that at all times during its operation, a vapour control system is free of vapour leaks and liquid leaks.

Sealed during operation

(2) All maintenance hatches and other openings in piping, tanks, vehicle tanks or other equipment that connect to the vapour space must be kept sealed during operation of the vapour control system, except during tank maintenance, inspection and repair.

Compatible fittings

51 (1) Before volatile petroleum liquids are loaded into a vehicle tank, the operator must ensure that the vehicle tank 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 volatile petroleum liquids are loaded into a vehicle tank, the operator must ensure that the operator of the vehicle provides evidence 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 was tested annually in accordance with the requirements set out in section 5.3.1 of the National Standard of Canada CAN/CGSB-3.1000-2019, entitled Vapour Control Systems in Gasoline Distribution Networks.

Internal Floating Roofs

Installation

52 An internal floating roof and any of its components, including seals and fittings, must be installed in accordance with its design specifications.

Float on surface of the liquid

53 (1) An internal floating roof must, at all times, float on the surface of the liquid and move 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 maximum of 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.

Remaining afloat

54 (1) An internal floating roof with multiple floatation compartments must be 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 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 and has a diameter greater than 6 m.

Double dead weight

(2) An internal floating roof must be 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

55 All seams in an internal floating roof that are exposed to vapour or liquid must

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

Continuous vapour-tight enclosure

56 (1) The internal floating roof must be equipped with a rim seal that forms a continuous vapour-tight enclosure around the entire perimeter of the floating roof, except where it is in contact with the tank wall, at which point the seal gap must meet the requirements set out in subsection 57(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; or
• (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 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 and measuring at least 30 cm in height.

Gap between seal and wall of tank

57 (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 in accordance with the control conditions and procedure for measuring seal gaps that are set out in Schedule 1.

Size

(2) The seal gap must be less than

• (a) 4 cm at every point and less than a cumulative total of 200 cm^{footnote 2} per m of the tank’s diameter, if the seal is the primary seal; and
• (b) 1.3 cm at every point and less than a cumulative total of 20 cm^{footnote 2} per m of the tank’s diameter, if the seal is a secondary seal.

More than one secondary seal

(3) If the internal floating roof is equipped with more than one secondary seal, only one of the secondary seals is required to meet the size requirements set out in paragraph (2)(b).

Openings

58 (1) Subject to subsections (2) and (3), all openings in the deck of an internal floating roof must be sealed at all times such that they are free of vapour leaks and liquid leaks.

Opening — passage of moving component

(2) The openings in the deck of an internal floating roof that allow a component of the tank to move relative to the floating roof when the liquid level in the tank changes must be 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 openings may be unsealed when necessary to prevent excess pressure or vacuum in the tank or for tank maintenance, inspection or repair.

Rims

59 An internal floating roof must be 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

60 Each component of an internal floating roof must be 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

61 An external floating roof and any of its components, including seals and fittings, must be installed in accordance with its design specifications.

Float on surface of the liquid

62 (1) An external floating roof must, at all times, float on the surface of the liquid and move 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 maximum of 30 days in a calendar year.

Remaining afloat

63 (1) An external floating roof must be a single-deck pontoon type or double-deck type 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 and has a diameter greater than 6 m; and
• (c) two adjacent compartments punctured and flooded with liquid, if the roof is a double-deck type and has a diameter greater than 6 m.

Rain

(2) An external floating roof must be 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 roof equipped with emergency drains that are designed to reduce the accumulation of water on the roof to a volume that the roof may safely support.

Exposed seams

64 All seams in an external floating roof that are exposed to vapour or liquid must

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

Continuous vapour-tight enclosure

65 (1) The external floating roof must be 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 it is in contact with the tank wall, at which point the seal gap must meet the requirements referred to in subsection 66(2).

Primary seal — types

(2) The primary seal must be 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 secondary seal must be of a type that is mounted on the rim of the external floating roof.

Not considered a secondary seal

(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

66 (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 in accordance with the control conditions and procedure for measuring seal gaps that are set out in Schedule 1.

Size

(2) The seal gap must be less than

• (a) 4 cm at every point and less than a cumulative total of 200 cm^{footnote 2} per m of the tank’s diameter, if the seal is the primary seal; and
• (b) 1.3 cm at every point and less than a cumulative total of 20 cm^{footnote 2} per m of the tank’s diameter, if the seal is a secondary seal.

More than one secondary seal

(3) If the external floating roof is equipped with more than one secondary seal, only one of the secondary seals is required to meet the size requirements set out in paragraph (2)(b).

Openings

67 (1) Subject to subsections (2) to (4), all openings in the deck of an external floating roof must be sealed at all times such that they are free of vapour leaks and liquid leaks.

Emergency drain

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

Opening — passage of moving component

(3) The openings in the deck of an external floating roof that allow a component of the tank to move relative to the floating roof when the liquid level in the tank changes must be 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 openings may be unsealed when necessary to prevent excess pressure or vacuum in the tank or for tank maintenance, inspection or repair.

Rims

68 An external floating roof must be 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

69 Each component of an external floating roof must be 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.

Pressure-Vacuum Vents

Requirements

70 A pressure-vacuum vent must meet the following requirements:

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

Ventilation

71 The tank may open to the atmosphere through the pressure-vacuum vent only, except during sampling, tank maintenance, inspection or repair or when the tank is not in service.

Alternative Emissions Control Equipment

Application for permit

72 (1) The operator may apply to the Minister for a permit to use alternative equipment rather than the emissions control equipment required under any of sections 31 to 33 and 35.

Prohibited substitutions

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

• (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 following information:

• (a) a technical description, including design schematics, of the alternative equipment;
• (b) a description of the circumstances in which the alternative equipment would be used, including
  • (i) the civic address, the name, if any, and the geographic coordinates of the facility in which the equipment would be operated,
  • (ii) the identifier and design specifications of any tank to which the equipment would apply,
  • (iii) the identifier, design specifications and the throughput from the previous calendar year of any loading rack to which the equipment would apply,
  • (iv) the types of volatile petroleum liquids that could be stored in any tank to which the equipment would apply, and
  • (v) the types of volatile petroleum liquids that could be loaded with any loading rack to which the equipment would apply;
• (c) a technical description of any procedures, maintenance practices or inspections that would be used to ensure the emissions control efficacy of the alternative equipment, including the frequency with which those procedures, maintenance practices or inspections would be performed and any criteria or objective parameters that would be used during an inspection;
• (d) an analysis demonstrating that the alternative equipment is at least as effective in controlling VOC emissions as the emissions control equipment required under any of sections 31 to 33 and 35, as applicable, in all the situations in which it would be used, supported either
  • (i) by the results of an emissions test performed with the alternative equipment on either full-sized tanks or full-sized loading racks, or on scale models, in which VOC emissions are measured under environmental and operating conditions representative of the conditions under which the alternative emissions control equipment would be used, or
  • (ii) by evidence demonstrating that the alternative equipment can operate free of vapour and liquid leaks and entirely contain VOC emissions from the source under normal operating conditions; and
• (e) a description of the analysis referred to in paragraph (d), including the experimental test methods and results, any supporting monitoring or measurement data and any calculations.

Multiple facilities

(4) The permit application may be for more than one of the operator’s facilities.

Clarifications

(5) The Minister may, on receiving the application, require that any clarifications be provided if they are necessary for the application to be considered.

Notice of change to information

(6) The operator must notify the Minister in writing of any change to the information provided under this section within five days after the day on which the operator is informed of the change.

Issuance

73 (1) Subject to subsection (2), the Minister may issue the permit referred to in subsection 72(1) if the Minister has determined that the operator has established that the analysis referred to in paragraph 72(3)(d) demonstrates that the alternative emissions control equipment is, in all cases in which it could be used, at least as effective at controlling VOC emissions as the equipment it would replace.

Refusal

(2) The Minister must refuse to issue the permit if

• (a) the Minister has reasonable grounds to believe that the operator has provided false or misleading information in support of their application; or
• (b) the information required under subsection 72(3) has not been provided or is insufficient to enable the Minister to consider the application.

Notice of refusal

(3) If the Minister refuses to issue a permit, the Minister must notify the operator in writing and must give them an opportunity to make written representations concerning the refusal.

Conditions of the permit

74 The Minister may set out in the permit conditions respecting

• (a) the design and operation requirements for the alternative emissions control equipment;
• (b) the circumstances in which the alternative emissions control equipment may be used;
• (c) the required procedures and practices for the maintenance, inspection and repair of the alternative equipment;
• (d) record-keeping requirements; and
• (e) any other requirement that the Minister considers necessary for the purpose of these Regulations.

Additional information

75 The Minister may require that any additional information be provided if the information is necessary to determine whether the conditions set out in the permit under section 74 are met or to determine the effectiveness of the alternative emissions control equipment.

Revocation

76 (1) The Minister must revoke a permit issued under subsection 73(1) if the Minister has reasonable grounds to believe that

• (a) the conditions set out in the permit under section 74 have not been met;
• (b) the alternative emissions control equipment does not control VOC emissions as effectively as the equipment that it replaced;
• (c) the operator has provided false or misleading information; or
• (d) the operator has not complied with other requirements of these Regulations.

Notice of revocation

(2) Before revoking a permit, the Minister must provide the operator with written reasons for the revocation and an opportunity to make written representations concerning the revocation.

Requirements for Inspection, Testing and Repair

Vapour Control Systems

Inspection and Tests

Inspection — every 30 days

77 (1) The operator must, every 30 days at a minimum, visually inspect all components of the vapour control system for vapour leaks or liquid leaks or any other defects that can be detected visually.

Inspection — annually

(2) The operator must, at least once in a calendar year and no more than 14 months after the day on which the previous inspection was performed, inspect the vapour control system for vapour leaks with any of the leak detection instruments referred to in subsection 20(1).

Records

(3) The operator must maintain a record of each inspection that contains the following information and any supporting documents:

• (a) the date of the inspection;
• (b) the identifier of the inspected vapour control system;
• (c) if the inspection is performed visually or using a leak detection instrument, and, in the latter case, the type of instrument that is used;
• (d) the results of the inspection, including a description and the location of any detected leak or defect; and
• (e) the name of the person who performed the inspection and the name of their employer.

Performance test — defects

78 The operator must test the performance of the vapour control system, at least once in a calendar year and no more than 14 months after the day on which the previous test was performed, for the defects referred to in subsection 82(3).

Performance test — modifications

79 (1) If the vapour control system is a vapour recovery system or vapour destruction system, the performance test referred to in section 78 must be performed in accordance with section 7 of the National Standard of Canada CAN/CGSB 3.1000–2019, 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 “VOC 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 test 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, either
  • (i) by using a device of a type that is insensitive to those substances, or
  • (ii) by 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 gas or 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 all 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.

Continuous monitoring device

(2) The measure of accuracy of a continuous monitoring device referred to in subsection 43 (1) is evaluated by comparing the measurements generated by the device during the test to the results of the performance test referred to in section 78.

Vapour balancing system — test

80 (1) If the vapour control system is a vapour balancing system, the performance test referred to in section 78 must cover the entire duration of the loading from a tank to a vehicle and the entire duration of the loading from a vehicle 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.

Records

81 The operator must maintain a record of each performance test performed on the vapour control system that contains the following information and any supporting documents:

• (a) the date of the test;
• (b) the identifier of the vapour control system that was tested;
• (c) the test methods followed;
• (d) the instruments used to perform the test;
• (e) the calibration test method for the instruments used to perform the test, the dates of the calibration tests and the results of the calibration tests;
• (f) the operating conditions under which the test is performed;
• (g) the results of the test and all data collected during the test;
• (h) any discrepancies identified between the results of the test and the performance indicated by the continuous monitoring device; and
• (i) the name of the person who performed the test and the name of their employer.

Repair

Repair — deadline

82 (1) The operator must repair a defect of the vapour control system no later than 15 days after the day on which it was detected.

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 defect must be repaired before the operation of the vapour control system is next required.

Defects

(3) The following situations constitute defects of a vapour control system:

• (a) a vapour leak or liquid leak;
• (b) if the system is a vapour recovery system or vapour destruction system, a continuous monitoring device that does not meet the requirements of section 43;
• (c) if the system is a vapour recovery system or vapour destruction system, insufficient VOC recovery or destruction performance under sections 47 to 49, as applicable;
• (d) if the system is a vapour balancing system, a measured pressure in excess of 4.5 kPa at the vehicle tank vapour outlet;
• (e) if the system is a vapour balancing system, open pressure-vacuum vents during loading activities; and
• (f) any other defect that is likely to reduce the vapour control system’s performance.

Records

(4) The operator must maintain a record of each repair that contains the following information and any supporting documents:

• (a) the identifier of the vapour control system and the identifier of the tank or loading rack on which the vapour control system was installed;
• (b) the date on which the defect was first detected;
• (c) a description of the defect;
• (d) the date of the repair; and
• (e) a description of the repair.

Internal Floating Roofs and External Floating Roofs

Inspection of Internal Floating Roof

Every 30 days

83 (1) The operator must inspect the space above the internal floating roof at least once every 30 days unless the tank is equipped with a vapour control system.

Inspection omitted

(2) Despite subsection (1), up to a maximum of three inspections in one calendar year may be omitted if weather conditions or unforeseen circumstances cause safety concerns or access problems that render inspection impracticable.

Inspection record

(3) The operator must document the reason why an inspection was omitted under subsection (2) in the inspection record.

Inspection

84 (1) An inspection referred to in subsection 83(1) must include

• (a) a visual inspection of the internal floating roof, using additional lighting if required, to determine if the defects referred to in paragraph 99(5)(e) or (f) are present; and
• (b) a determination of the value of the LEL% in the space above the internal floating roof in accordance with the control conditions and procedure described in Schedule 2.

Control conditions

(2) During at least one of the inspections referred to in subsection 83(1) that are performed each calendar year, the control conditions set out in paragraph 1(e) of Schedule 2 must be met.

Baseline LEL%

85 (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 the total replacement of the primary or secondary seal;
• (b) all values of the LEL% that exceed 20, or 10 if the benzene concentration of the volatile petroleum liquid in the tank is equal to or greater than 20% by weight; 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.

Maximum thresholds

(5) The value of the LEL% in the space above the internal floating roof must be 20 or less and below the following thresholds:

• (a) 150% of the baseline LEL%, if the baseline LEL% is greater than 5;
• (b) 7.5, if the baseline LEL% is less than 5; and
• (c) 10, if the benzene concentration of the volatile petroleum liquid in the tank is equal to or greater than 20% by weight.

Excess LEL% — first inspection

(6) Subject to subsection (7), if, during a first inspection, the value of the LEL% is in excess of one of the thresholds set out in subsection (5), that value is considered to be a defect under subsection 99(5) or (6).

Excess LEL% — second inspection

(7) If, during the first inspection referred to in subsection (6), the value of the LEL% does not exceed one of the thresholds set out in subsection 99(6), 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 one of the thresholds set out in subsection (5), the value determined during the first inspection is not considered to be a defect under subsection 99(5) or (6).

Inspection — every 20 years

86 The operator must inspect the interior of the tank and the internal floating roof every 20 years while the tank is not in service and the inspection must include

• (a) a measurement of the seal gap in accordance with the control conditions and procedure set out in Schedule 1, 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 guide pole 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 hatch system to verify that it seals automatically after use;
• (d) 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 applicable, an inspection of the inside of the pontoons and a determination of the value of the LEL% inside of 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 alarms and automatic gauging systems and alarms;
• (j) an inspection of the internal floating roof’s guide poles or stabilizers that prevent rotation, including the attachment welds between the guide pole and the tank wall, for corrosion, wear, distortion and alignment;
• (k) if applicable, a visual inspection inside the guide pole for protrusions that are likely to damage the vapour control float;
• (l) if applicable, an inspection of the vapour control float or cover inside the guide pole;
• (m) an inspection of the liquid inlet diffuser pipe and supports for corrosion, erosion and thinning; and
• (n) an inspection of the internal wall of the tank for grooving, corrosion, coating failures and out of roundness.

Inspection of External Floating Roof

Every 30 days

87 (1) The operator must visually inspect the upper surface of the external floating roof at least once every 30 days for the defects referred to in paragraphs 99(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 the inspection impracticable, the operator must perform the inspection without delay when the circumstances permit but must not delay the inspection by more than seven days.

Inspection record

(3) The reason why an operator has delayed an inspection under subsection (2) must be documented in the inspection record.

Annual inspection

88 (1) The operator must visually inspect the upper surface of the external floating roof annually – with each inspection performed no more than 14 months after the day on which the previous inspection was performed – for the defects referred to in paragraphs 99(5)(a) and (c) to (h) and measure the secondary seal gaps annually in accordance with the control conditions and procedure set out in Schedule 1.

No more than two metres

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

Inspection — every five years

89 The operator must inspect the exp osed part of the internal wall of the tank and the external floating roof every five years, and the inspection must include

• (a) a measurement of the primary seal gaps in accordance with the control conditions and procedure set out in Schedule 1, unless the rim seal is being replaced at the time of the inspection;
• (b) an inspection of 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 seal 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 guide pole 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 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 liquid leaks or vapour leaks;
• (g) an inspection of wind girder for corrosion damage;
• (h) a visual inspection of the floating roof for inadequate drainage;
• (i) if applicable, a test operation of the hatch system to verify that it seals 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 for adequate covers or sealing;
• (m) if applicable, an inspection of the inside of 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 on the roof; and
• (o) if applicable, an inspection of the bolting bar on the rim-mounted secondary seals for corrosion and broken welds.

Inspection — every 20 years

90 The operator must inspect the interior of the tank and the external floating roof every 20 years while the tank is not in service and the inspection must include

• (a) the servicing, testing or replacement of the vents and vacuum breakers to ensure that they are in good working order and that they remain closed when the floating roof is floating on the liquid;
• (b) an inspection of the floating roof and all other emissions control equipment for structural defects and corrosion;
• (c) an inspection of the seams in the external floating roof for potential vapour leaks or liquid leaks, openings or damage;
• (d) an inspection of the upper and lower surfaces of the external floating roof for corrosion and damage;
• (e) an inspection of the drains on the external floating roof for corrosion, damage and proper functioning;
• (f) an inspection of the external floating roof’s guide poles or stabilizers that prevent rotation including attachment welds between the guide pole and the tank wall for corrosion, wear, distortion and alignment;
• (g) if applicable, a test operation of the alarms and automatic gauging systems and alarms;
• (h) if applicable, a visual inspection inside the guide pole for protrusions that are likely to damage the vapour control float;
• (i) if applicable, an inspection of the vapour control float or cover inside the guide pole;
• (j) an inspection of the liquid inlet diffuser pipe and supports for corrosion, erosion and thinning; and
• (k) an inspection of the internal wall of the tank for grooving, corrosion, coating failures and out of roundness.

Seal replacement measurement

91 Within 60 days after the day on which a seal is replaced, the operator must measure the seal gaps in accordance with the control conditions and procedure set out in Schedule 1.

Inspector Certificate

92 The operator must ensure that all inspections referred to in sections 86, 89 and 90 are performed by a person who holds a valid API 653 — Aboveground Storage Tank Inspector certificate issued by the American Petroleum Institute.

Records

93 The operator must maintain a record of each inspection of the internal floating roof or external floating roofs that contains the following information and any supporting documents:

• (a) the date of the inspection;
• (b) the identifier of the inspected tank;
• (c) all inspection activities that are performed and the method by which they are performed;
• (d) the results of the inspection, including a description and the location of any detected defects;
• (e) the reason for any omission of an inspection under subsection 83(2) or delays in the required inspection intervals under subsection 87(2);
• (f) in the case of an internal floating roof, the baseline LEL%, including the calculation of the baseline LEL% under subsection 85(2), if applicable;
• (g) in the case of an inspection performed under section 86, 89 or 90, the name of the person who performed the inspection and proof demonstrating that they hold the certificate required under section 92;
• (h) any measurement of a seal gap that was taken in accordance with subsection 88(1) or section 89 or 91;
• (i) any inspection intervals reduced under section 94; and
• (j) in the case of any other inspection of the internal floating roof or external floating roof, the name of the person who performed the inspection and the name of their employer, if applicable.

Other requirements

Reduced inspection intervals

94 If design specifications or inspection findings indicate that the estimated life expectancy of any component of an internal floating roof or an external floating roof is shorter than the relevant inspection intervals specified in section 86, 89 or 90, as the case may be, the interval between inspections in respect of the component must be reduced to match its estimated life expectancy.

Report to Minister

95 (1) Whenever a defect of an internal floating roof or external floating roof is detected and two or more defects were detected in that roof in the 24-month period preceding the most recent detection, the operator must submit a report to the Minister within 30 days after the most recent detection.

Information

(2) The report must include the following information:

• (a) the identifier of the tank in which the defects were detected;
• (b) a description of the liquids stored in the tank, including their TVP and benzene concentration;
• (c) the dates on which the defects were detected;
• (d) a description of the defects detected;
• (e) a description of all repairs to which have been made to the defects; and
• (f) a description of all steps that have been taken or will be taken, if any, to reduce the risk of the defects recurring.

Inspections of Existing Tanks Performed Before the Coming into Force of These Regulations

Inspection periods

96 (1) For existing tanks, the inspections referred to in sections 86 and 90 begin on the later of the following days:

• (a) the day on which the tank was first in service, provided that the operator’s tank records demonstrate that all tests or inspections verifying that correct installation and function of the equipment required by design specifications have been performed; and
• (b) the day on which the most recent internal inspection of the tank was performed, provided that 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.

Conditions not met

(2) If the conditions referred to in paragraph (1)(a) and (b) are not met, the inspection must be completed within the period referred to in section 113.

Defects

97 For the purposes of sections 98 and 99, all defects detected during an inspection of a 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.

Repair

Repair — tank not in service

98 Any defect of a tank, external floating roof or internal floating roof that is present when the tank is not in service must be repaired before the tank returns to service.

Repair — tank in service

99 (1) Subject to subsections (2), (3), (5) and (6), if a defect is detected when a tank is in service, the operator must take one of the following measures:

• (a) in the case of a defect of a tank, external floating roof or internal floating roof, the operator must within 45 days after the day on which the defect is detected
  • (i) remove the tank from service, or
  • (ii) repair the defect; or
• (b) in the case of a defect of a tank equipped with an internal floating roof or a defect of an internal floating roof, the operator must equip the tank with a temporary vapour control system within five days after the day on which the defect is detected and repair the defect within 135 days after that day.

Tank designated under subsection 115(1)

(2) Subject to subsection (6), if a defect of a tank designated under subsection 115(1) can be repaired only when the tank is not in service, the repair may be delayed until it is required to be completed under section 98.

Defect to rim seal — 75 days

(3) A defect to a rim seal must be repaired within 75 days after the day on which it is detected if

• (a) the measurement of the seal gap is less than the cumulative total surface area of all seal gaps is less than 1000 cm^{footnote 2} per m of the tank’s diameter; and
• (b) within 30 days of the detection of the defect,
  • (i) a person who holds a valid API 653 — Aboveground Storage Tank Inspector certificate issued by the American Petroleum Institute has determined 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, and
  • (ii) the operator has added that person’s determination under subparagraph (i), and an indication that the repair will be attempted while the tank is in service, to the tank records referred to in section 105.

Repair cannot be completed

(4) If, after attempting a repair under subsection (3), the operator determines that 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) The following situations constitute defects of an internal floating roof or external floating roof:

• (a) a tank that does not meet the requirements of section 30 such that the efficacy of the internal or external floating roof in relation to emissions control could be reduced;
• (b) a seal gap that exceeds the size requirements set out in subsections 57(2) and (3) and 66(2) and (3);
• (c) an opening that does not meet the requirements of sections 58 and 67;
• (d) a value of the LEL% that exceeds the thresholds set out in subsection 85(5);
• (e) in the case of an external floating roof, inadequate drainage that affects the roof’s capacity to remain afloat on the surface of the liquid;
• (f) the presence of volatile petroleum liquids on the upper surface of the internal floating roof or external floating roof over an area of more than 1 m² or the presence of the volatile petroleum liquid on the upper surface of the internal floating roof or the external floating roof that is observed more than once in a 12-month period;
• (g) a structural defect of the internal floating roof or external floating roof that could reduce the efficacy of the internal floating roof or the external floating roof in relation to emissions control; and
• (h) any other defect that could reduce the efficacy of the internal floating roof or the external floating roof in relation to emissions control.

Major defects

(6) If the internal floating roof or external floating roof has sunk, if the value of the LEL% in a high benzene tank exceeds 20 or the value of the LEL% in a tank designated under paragraph 7(c) or (d) exceeds 50, the operator must, as soon as feasible after the defect is detected, cease loading volatile petroleum liquids into the tank and

• (a) empty the tank of all volatile petroleum liquid within five days after the day on which the defect is detected; or
• (b) in the case of a tank that is equipped with an internal floating roof, equip the tank with a temporary vapour control system within five days after the day on which the detection of the defect, and repair the defect within 135 days after that day.

Records

(7) The operator must maintain a records of each repair made under this section and section 98 that contains the following information and supporting documents:

• (a) the identifier of the tank;
• (b) the date on which the defect was first detected;
• (c) a description of the defect;
• (d) the date of the repair; and
• (e) a description of the repair.

VOC Emissions Reduction Plan

Cleaning tank or replacing seal

100 (1) The operator must develop a plan to reduce VOC emissions before cleaning the interior of a tank or replacing the rim seal of an internal floating roof or external floating roof of the tank while it is in service and must implement that plan during the cleaning or replacement.

Emissions reduction plan

(2) The emissions reduction plan must include a description of the planned cleaning or replacement activities that are likely to cause VOC emissions and the measures that are to be taken to reduce those emissions, including at least one of the following measures in the case of the cleaning the interior of a tank:

• (a) the completion the cleaning of the tank within 48 hours after the internal floating roof is no longer floating on the surface of the liquid;
• (b) the dilution or chemical decontamination of the liquid in the tank such that the liquid is no longer considered to be a volatile petroleum liquid; or
• (c) the equipping of the tank with a temporary vapour control system.

Pressure-Vacuum Vent

Inspection

Pressure-vacuum vent

101 (1) The operator must inspect the pressure-vacuum vent annually and no more than 14 months after the day on which the last inspection was carried out to ensure that it meets the requirements set out in paragraphs 70(a) and (b).

Five years

(2) The operator must inspect the pressure-vacuum vent every five years to ensure it meets the requirements set out in paragraph 70(c).

Repair

Defect detected

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

Types of defects

(2) Failure to meet the requirements in paragraphs 70(a) to (c) constitute a defect of a pressure-vacuum vent.

Records

(3) The operator must maintain a record for each repair made to the pressure-vacuum vent that contains the following information and supporting documents:

• (a) the identifier of the tank in which the defect was detected;
• (b) the date when the defect was first detected;
• (c) a description of the defect;
• (d) the date of the repair; and
• (e) a description of the repair.

Detection — tank not in service

(4) If the tank is not in service at the time the defect of the pressure-vacuum vent is detected, the defect must be repaired before the tank returns to service.

Extended Repair Plan

Reasons

103 (1) The operator may develop and implement an extended repair plan for a tank, an internal floating roof or external floating roof, if the tank would have to be removed from service so that a defect may be repaired but the tank cannot, for any of the following reasons, be removed from service such that the repair may be completed within the time limit for repair under section 99:

• (a) the removal from service of the tank would require a shutdown of some or all of the petroleum processing equipment at the facility and, at any time between the day on which the defect was detected and the day that would otherwise be the time limit for the repair of the defect,
  • (i) at least 10%, rounded up to the nearest whole number, of the total number of tanks at the facility with an internal volume greater than or equal to 100 m³, is removed from service for a period not exceeding one year for cleaning, maintenance or construction, or
  • (ii) at least 20%, rounded up to the nearest whole number, of the total number of tanks at the facility that, immediately before their removal from service, contain a liquid used or sold by the facility interchangeably with a liquid contained in the tank that requires repair, is removed from service for a period not exceeding one year for cleaning, maintenance or construction;
• (b) an authorized official determines that there are no options at the facility or off-site of the facility for the storage, processing, treatment or disposal of the contents of the tank; or
• (c) an authorized official determines that 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.

Definition of authorized official

(2) For the purposes of subsection (1), authorized official means

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

Cease loading

(3) If the operator intends to implement an extended repair plan for a reason referred to in paragraph (1)(b) or (c), the operator must cease loading any volatile petroleum liquids into the tank within the following timelines:

• (a) in the case of a defect referred to in subsection 99(6), as soon as the defect is detected; or
• (b) in the case of any other defect, within 30 days after the day on which the defect is detected.

Notice to Minister

(4) If the operator intends to implement an extended repair plan, the operator must, within 30 days after the day on which the defect is detected, notify the Minister in writing of that intention and provide the Minister with a copy of the extended repair plan, that includes the following information:

• (a) the reason invoked under subsection (1) requiring the implementation of an extended repair plan;
• (b) information demonstrating that the reasons set out in subsection (1) apply;
• (c) the identifier of the tank in which the defect was detected;
• (d) a description of the liquids stored in the tank, including their TVP and benzene concentration;
• (e) the date on which the defect was detected;
• (f) a description of the defect;
• (g) the time required to remove the tank from service and the reason why that amount of time is required; and
• (h) a description of the planned repair, including a description of any measures that will be taken to mitigate VOC emissions until the defect is repaired.

Removal from service — time limit

(5) The removal from service of the tank must be completed within the time limit indicated in the extended repair plan and the period during which the tank is not in service must not, under any circumstances exceed 135 days, as calculated as beginning on the day on which the defect was detected.

Major defects — time limit

(6) If the defect is one referred to in subsection 99(6), the operator must remove the tank from service within 10 days after the day on which the defect was detected.

Inventory

Inventory

104 (1) The operator must establish and keep at their facility an inventory that contains the following information in respect of every tank designated under section 7 and every loading rack designated under subsection 8(1):

• (a) the identifier of the tank or loading rack;
• (b) whether the tank is not in service and the date when it was removed from service;
• (c) whether the tank is an existing tank or the loading rack is an existing loading rack;
• (d) whether the tanks is designated as an intermittent service tank under subsection 5(1);
• (e) the category to which the tank has been designated as belonging under section 7 or to which the loading rack has been designated as belonging under or 8(1);
• (f) the type of emissions control equipment that is being used with respect to the tank or loading rack; and
• (g) whether the tank or loading rack has been designated under section 115.

Update

(2) The operator must update the inventory within five days after the day on which any information provided under subsection (1) changes.

Record-Keeping

Records

Tanks

105 The operator must maintain, in respect of each tank that is designated under section 7 and each tank that was so designated in the preceding six years, a record that contains the following information and any supporting documents:

• (a) the design specifications of the tank and the year of the tank’s installation;
• (b) the name or description of each liquid stored in the tank, the date on which the tank first contained the liquid and the dates on which the tank was not in service;
• (c) in the case of a tank designated as an intermittent service tank under subsection 5(1), information to establish that it has been in service for less than 300 total hours per calendar year;
• (d) the statistical or engineering analysis that demonstrates the quantification of the variation of substance properties of a volatile petroleum liquid referred to in subsection 5(2), if applicable;
• (e) the designation of the tank under section 7, if any, the date when it was first designated, any changes made to the designation and the date when those changes were made;
• (f) the method used to determine the properties of the liquids stored in the tank and the testing results, if any, including the benzene concentration and TVP, and the VOC concentration of those liquids;
• (g) the type of all emissions control equipment installed on the tank during its lifespan, including the year of the equipment’s installation;
• (h) the design specifications of the emissions control equipment required under section 41, 52, 61, and 70, and subparagraph 72(3)(b)(ii) and information that validates the installation of that equipment on the tank;
• (i) if a vapour control system is used as the tank’s emissions control equipment, the periods when the vapour control system was not in service and the reason why the system was not in service;
• (j) if a temporary vapour control system is used as the tank’s emissions control equipment, the start date of its use;
• (k) the maintenance, inspection and repair records of the tank and of any emissions control equipment installed on the tank;
• (l) the information required under subparagraph 99(3)(b)(ii) if applicable;
• (m) the emissions reduction plan required under section 100 if applicable;
• (n) a maintenance plan for the tank that indicates the type of inspection, the frequency of inspections or the latest allowable date of the next inspection of each type that is required to be performed on the tank under these Regulations, taking into account any applicable reduction of the inspection intervals under section 94; and
• (o) if the tank is designated under section 115, the date when it was first designated, any changes made to the designation and the date when those changes were made.

Loading racks

106 The operator must maintain, for each loading rack designated under subsection 8(1) or any loading rack that had a designation under subsection 8(1) in the preceding six years, a record that contains the following information and any supporting documents:

• (a) the current designation of the loading rack under subsection 8(1), if any, the date when it was first designated, any changes made to the designation and the date when those changes were made;
• (b) the method to determine the properties of the liquids and the testing results, if any, of the properties of the liquids that are with the loading rack, including the benzene concentration and TVP, and the VOC concentration of those liquids;
• (c) the name or description of each liquid that is loaded with the loading rack, the volume of each liquid loaded per day and whether the loading was done while the vapour control system was not in service and without the use of a temporary vapour control system;
• (d) the type of all emissions control equipment installed on the loading rack during its lifespan, including the year of the equipment’s installation;
• (e) the design specifications of the emissions control equipment referred to in paragraph (d) and information that validates the installation of the equipment on the loading rack;
• (f) the periods when the vapour control system was not in service and the reason the system was not in service;
• (g) if a temporary vapour control system is used as the loading rack’s emissions control equipment, the start date of its use;
• (h) the maintenance, inspection and repair records for the emissions control equipment installed on the loading rack; and
• (i) if the loading rack is designated under section 115, the date when it was first designated any changes made to the designation, and the date when those changes were made.

Measurements and calculations

107 The operator must maintain a record, along with any supporting documents of each measurement and calculation that is used to determine the value of an element of a formula set out in these Regulations including the methodology that is used to determine that value.

Training completed

108 The operator must maintain a record that contains the following information in respect of any training completed by any person, including a qualified professional, in relation to the duties to be carried out under section 16, 22 or 29:

• (a) the name, title and business address of the person and the name of their employer;
• (b) the date when the training was completed;
• (c) the name of the entity that provided the training; and
• (d) a description of the training.

Minister’s request — records

109 (1) On the Minister’s request, the operator must, within 30 days after the day on which the request was made, provide the Minister with a copy of any of the records required to be maintained by the operator 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 stored in a tank or that is loaded with a loading rack.

Retention of Records

Six years

110 (1) The operator must ensure that any record required to be maintained under these Regulations is retained for a period of at least six years after the day on which the record is made.

Internal tank inspections

(2) Despite subsection (1), the records of any internal tank inspections performed under section 86 or 90 and any repair made as a result of the findings of the inspection must be retained until the day on which the next internal inspection of the tank is performed under that section.

Electronically readable format

(3) Records that are retained electronically must be in an electronic format that is compatible with the format that is used by the Minister for the period referred to in subsection (1) or (2), as the case may be.

Location of records

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

Language

(5) 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

111 (1) The operator must submit to the Minister a report of registration of the facility that contains the following information:

• (a) the name of the operator;
• (b) the civic address, the name, if any, and the geographic coordinates of the facility;
• (c) the civic address of the location where records are retained under these Regulations if it is different than that of the facility;
• (d) the name, title, civic and postal addresses, telephone number and email address of a contact person;
• (e) the facility’s National Pollutant Release Inventory identification numbers, if any;
• (f) a description of the activities that the facility is engaged in;
• (g) the inventory established under section 104, including
  • (i) for each tank listed in the inventory,
    • (A) the internal volume of the tank in m³ and the height and diameter of the tank in metres,
    • (B) the name or description of the liquid stored in the tank and the properties of that liquid, including its benzene concentration and TVP, and, if the liquid stored in the tank is an oil-water mixture, its VOC concentration as determined by any method that conforms to generally accepted engineering practices, including the use of physical simulation, standard reference texts or supplier specifications;
  • (ii) for each tank at the facility that is not listed in the inventory, that has an internal volume greater than or equal to 100 m³ and that is either currently storing or capable of storing any kind of petroleum liquid, including petroleum liquids not classified as volatile petroleum liquids,
    • (A) the internal volume of the tank in m³ and the height and diameter of the tank in metres, and
    • (B) the name or description of the liquid stored in the tank, and
  • (iii) for each loading rack listed in the inventory, the loading rack’s annual throughput of each volatile petroleum liquid and of each vehicle type for the previous calendar year; and
• (h) the total number of tanks for which information is provided under subparagraphs (g)(i) and (ii).

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.

Deadline — operation before coming into force

(3) Despite subsection (2), the operator of a facility that begins operating before the day on which these Regulations come into force must submit the report of registration within 120 days after the day on which these Regulations come into force.

Change in information

(4) The operator must notify the Minister of any change to the information provided in the report of registration under paragraphs (1)(a) to (f) within five days after the day on which the change occurs.

Annual submission

(5) Each year, the operator must submit to the Minister the information required under paragraphs (1)(a) to (g) within 30 days after the anniversary of the day on which these Regulations come into force.

Delayed Application — Existing Tanks and Loading Racks

Delay

Floating roofs

112 The requirements set out in sections 54 to 55, subsection 56(2), sections 58 to 60, 63 and 64, subsections 65(2) and (3) and sections 67 to 69 apply to existing tanks equipped with an internal floating roof or external floating roof, except for high benzene tanks, beginning on the day on which any of the following situations occur:

• (a) an inspection of the tank is performed in accordance with section 86 or 90;
• (b) the time limit for the inspection of the tank under section 86 or 90 has passed;
• (c) in the case of a tank equipped with an external floating roof, the roof is repaired in accordance with section 99; or
• (d) in the case of a tank that is removed from service, the tank is returned to service.

First anniversary — existing tanks

113 (1) The requirements set out in sections 83 to 90 and 99 apply to existing tanks beginning on the first anniversary of the day on which these Regulations come into force.

High benzene tanks

(2) The requirements set out in sections 28 and 31 apply to existing tanks that are high benzene tanks beginning on the first anniversary of the day on which these Regulations come into force.

High benzene loading racks

(3) The requirements set sections 28 and 35 apply to existing loading racks that are designated as high benzene loading racks under paragraph 8(1)(a) beginning on the first anniversary of the day on which these Regulations come into force.

Third anniversary — existing tanks

114 (1) The requirements set out in section 28 and sections 31 to 33 apply to existing tanks, except for high benzene tanks, beginning on the third anniversary of the day on which these Regulations come into force.

Third anniversary — existing loading racks

(2) The requirements set out in sections 28 and 35 apply to existing loading racks, except for loading racks that are designated as high benzene loading racks under paragraph 8(1)(a), beginning on the third anniversary of the day on which these Regulations come into force.

Additional Period of Delayed Application

Designation

115 (1) Subject to subsections (4) and (5) and sections 116 to 120, the operator may designate an existing tank as a delayed application tank or an existing loading rack as a delayed application loading rack, and benefit from an additional period conform with the requirements referred to in section 114.

High benzene

(2) A designation referred to in subsection (1) must not be applied to a high benzene tank or to a loading rack that is designated as a high benzene loading rack under paragraph 8(1)(a).

Inventory and documents

(3) A designation referred to in subsection (1) must be set out in the inventory established under section 104 and indicated in the record maintained in respect of the tank or loading rack under section 105 or 106.

At least two existing tanks

(4) An existing tank may be designated under subsection (1) if at least two existing tanks at the facility have been equipped with either an internal floating roof or a vapour control system after the day on which these Regulations come into force.

Loading factor

(5) If the total loading factor of a facility calculated in accordance with the method set out in section 1 of Schedule 3 is greater than or equal to 7 on the day on which these Regulations come into force, an existing loading rack 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 the day on which these Regulations come into force.

Fourth year — tanks

116 (1) In the fourth year after the day on which these Regulations come into force , the number of existing tanks that may be designated under subsection 115(1) at a facility may 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 paragraph 111(1)(h); and
• (b) 12.

Two loading racks

(2) In the fourth year after the day on which these Regulations come into force, no more than two loading racks at a facility may be designated under subsection 115(1).

Fifth year — tanks

117 (1) In the fifth year after the day on which these Regulations come into force, the number of existing tanks may be designated under subsection 115(1) at a facility may 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 paragraph 111(1)(h); and
• (b) nine.

One loading rack

(2) In the fifth year after the day on which these Regulations come into force, no more than one loading rack at a facility may designated under subsection 115(1).

Sixth year — tanks

118 (1) In the sixth year after the day on which these Regulations come into force, the number of existing tanks that may be designated under subsection 115(1) at a facility may 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 paragraph 111(1)(h); and
• (b) six.

No loading racks

(2) Beginning in the sixth year after the day on which these Regulations come into force, no loading racks at a facility may be designated under subsection 115(1).

Seventh year — tanks

119 In the seventh year after the day on which these Regulations come into force, the number of existing tanks that may be designated under subsection 115(1) at a facility may 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 paragraph 111(1)(h); and
• (b) three.

Eighth year — no tanks

120 Beginning in the eighth year after the day on which these Regulations come into force, no existing tanks at a facility may be designated under subsection 115(1).

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

121 The schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) ^{footnote 40} 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) section 28 (b) section 30 (c) section 31 (d) section 32 (e) section 33 (f) section 34 (g) section 35 (h) section 36 (i) section 40 (j) section 42 (k) subsection 43(1) (l) subsection 45(1) (m) section 46 (n) subsection 47(1) (o) subsection 48(1) (p) subsection 49(2) (q) section 50 (r) subsection 51(1) (s) section 52 (t) subsection 53(1) (u) section 54 (v) section 55 (w) subsection 56(1) (x) subsection 58(1) (y) section 59 (z) section 60 (z.1) section 61 (z.2) subsection 62(1) (z.3) section 63 (z.4) section 64 (z.5) subsection 65(1) (z.6) subsection 66(1) (z.7) subsection 67(1) (z.8) section 68(1) (z.9) section 69(1) (z.91) section 70(1) (z.92) subsection 82(1) (z.93) section 96 (z.94) subsection 97(1) (z.95) subsection 100(1)

Coming into Force

Registration

122 These Regulations come into force on the day on which they are registered.

SCHEDULE 1

(Subsections 57(1) and 66(1), paragraph 86(a), subsection 88(1), paragraph 89(a) and section 91)

Measuring Seal Gaps for Floating Roof Tanks

Control Conditions

1 The measurement of the seal gap of a floating roof tank must be performed under the following control conditions:

• (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 while measurements are being taken;
• (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 is pulled away from the tank wall, removed, or otherwise positioned such that it will not interfere with the measurement.

Procedure

2 The following procedure must be followed to measure the seal gap of a floating roof tank:

• (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 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 (c) (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) sum 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 cm^{footnote 2} per m.

SCHEDULE 2

(Paragraph 84(1)(b) and subsection 84(2))

Measuring VOC Vapour Concentration in Internal Floating Roof Tanks

Control Conditions

1 The measurement of VOC vapour concentration in the space between the fixed roof and the floating roof of an internal floating roof tank must be performed under the following conditions:

• (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 that precedes the taking of the measurement;
• (b) the wind speed must be less than 10 km/h while a measurement is being taken (unless the average monthly wind speed in the month when the measurement is taken exceeds 10 km/h, as determined at the nearest meteorological observation station to the facility that is listed in the most recent Canadian Climate Normals data set published by Meteorological Service of Canada, in which case the measurement must instead be taken when the wind speed is less than 15 km/h);
• (c) the measurement must be taken at a vertical distance of between 2 and 4 m below the fixed roof, (unless the vertical distance between the fixed roof and the floating roof is less than 3 m, in which case the measurement must instead be taken at half of the vertical distance between the fixed roof and the floating roof);
• (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; and
• (e) in the case of an inspection referred to in subsection 84(2) of these Regulations, the liquid level in the tank must:
  • (i) be at or above half of the highest design liquid fill level of the tank,
  • (ii) not have changed during the four-hour period that precedes the taking of the measurement, and
  • (iii) not change while the measurement is being taken.

Procedure

2 The following procedure must be followed to measure the VOC vapour concentration in the space between the fixed roof and the floating roof of an internal floating roof tank:

• (a) use an instrument referred to in subsection 20(2) of these Regulations;
• (b) record:
  • (i) the type of instrument that was used,
  • (ii) the estimated wind speed at the time of the measurement,
  • (iii) the volume of liquid in the tank at the time of the measurement, eight hours before the time of the measurement, and, in the case of an inspection referred to in subsection 84(2) of these Regulations, four hours before the time of the measurement, 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 conversion calculation and the converted value.

SCHEDULE 3

(Clauses 8(1)(c)(i)(A) and (B) and 8(1)(c)(ii)(A) and (B), subparagraph 46(b)(ii) and subsection 115(5))

Calculation of Loading Factors

Total Loading Factor

1 The total loading factor of a facility for the previous calendar year must be calculated according to the following method:

• (a) determine the TVP and the benzene concentration of the liquid of each volatile petroleum liquid loaded at the facility;
• (b) for fixed roof tanks and each type of vehicle receiving volatile petroleum liquids with a loading rack, calculate the loading factor for each volatile petroleum liquid as determined by the formula

  LF = V ÷ ( F_benz × F_TVP × F_load × 25 000)

  where

  LF

  is the loading factor;

  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_TVP

  is the value set out in column 2 of Table 2 to this section for the TVP 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) for fixed roof tanks and each type of vehicle receiving volatile petroleum liquids with a loading rack at the facility, determine the volume of each volatile petroleum liquid, in standard m³, that is 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) in the case of a vehicle, if the liquid loaded is not a volatile petroleum liquid and the liquid most recently contained in the vehicle tank was a volatile petroleum liquid and the vapours were not purged to a vapour control system before the the liquid that is not a volatile petroleum liquid was loaded, the liquid loaded is considered to be the volatile petroleum liquid that was most recently contained in the vehicle tank, and
  • (iii) if a loading rack was equipped with a vapour control system in accordance with section 35 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
• (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 table i1 note 1	1
3	1.1 to 2.0	0.6
4	2.1 to 10.0	0.2
5	Greater than 10	0.02
Table i1 note(s) Table i1 note 1 Use Fbenz =1 for gasoline, regardless of actual benzene concentration Return to table i1 note 1 referrer

TABLE 2

Item	Column 1 TVP (kPa)	Column 2 FTVP
1	3.5 to 10.0	1
2	10.1 to 35.0	2.8
3	35.1 to 65 table i2 note 1	1
4	Greater than 65	0.4
Table i2 note(s) Table i2 note 1 Use FTVP =1 for gasoline, regardless of actual benzene concentration Return to table i2 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

Total Daily Loading Factor

2 The total daily loading factor of a facility must be calculated according to the following method:

• (a) determine the TVP and the benzene concentration of the liquid of each volatile petroleum liquid loaded at the facility;
• (b) for fixed roof tanks and for each type of vehicle receiving volatile petroleum liquids with a loading rack, calculate the daily loading factor for each volatile petroleum liquid as determined by the formula

  DLF = V_D ÷ F_D

  where

  DLF

  is the daily loading factor,

  V_D

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

  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, the benzene concentration referred to in column 2 and the TVP set out in column 3, as applicable;

• (c) for fixed roof tanks and for each type of vehicle receiving volatile petroleum liquids through a loading rack, determine the highest volume of each volatile petroleum liquid, in standard m³, that is loaded without the use of a vapour control system during a day in the previous calendar year, taking into account the following modifications, if applicable:
  • (i) if the liquid loaded is not a volatile petroleum liquid and the most recent liquid contained in the vehicle tank was a volatile petroleum liquid and the vapours were not purged to a vapour control system prior to loading the liquid that is not a volatile petroleum liquid, the liquid loaded is considered to be the volatile petroleum liquid that was most recently contained in the vehicle tank, and
  • (ii) if a loading rack was equipped with a vapour control system in accordance with section 35 during that day, the volume of volatile petroleum liquid loaded with that loading rack is not included in the calculation of the volume; and
• (d) calculate the sum of the daily loading factors calculated in paragraph (b), which constitutes the facility’s total daily loading factor.

TABLE

Item	Column 1 Loading Recipient	Column 2 Benzene Concentraton (% by weight)	Column 3 FD
1	Truck, railcar, vehicle other than ship or transport barge, fixed roof tank	(1) Less than 0.5	(a) 10 000, if TVP is less than 35 kPa (b) 2 000, if TVP is greater than or equal to 35 kPa
		(2) 0.5 to 1 table i4 note 1	500
		(3) Greater than 1	30
2	Ship or transport barge	(1) Less than 0.5	(a) 15 000, if TVP is less than 35 kPa (b) 4 000, if TVP is greater than or equal to 35 kPa
		(2) 0.5 to 1 table i4 note 2	1 100
		(3) Greater than 1	50
Table i4 note(s) Table i4 note 1 Use FD =500 for gasoline, regardless of actual benzene concentration Return to table i4 note 1 referrer Table i4 note 2 Use FD =1100 for gasoline, regardless of actual benzene concentration Return to table i4 note 2 referrer

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Privacy notice

The information you provide is collected under the authority of the Financial Administration Act, the Department of Public Works and Government Services Act, the Canada–United States–Mexico Agreement Implementation Act,and applicable regulators’ enabling statutes for the purpose of collecting comments related to the proposed regulatory changes. Your comments and documents are collected for the purpose of increasing transparency in the regulatory process and making Government more accessible to Canadians.

Personal information submitted is collected, used, disclosed, retained, and protected from unauthorized persons and/or agencies pursuant to the provisions of the Privacy Act and the Privacy Regulations. Individual names that are submitted will not be posted online but will be kept for contact if needed. The names of organizations that submit comments will be posted online.

Submitted information, including personal information, will be accessible to Public Services and Procurement Canada, who is responsible for the Canada Gazette webpage, and the federal institution managing the proposed regulatory change.

You have the right of access to and correction of your personal information. To seek access or correction of your personal information, contact the Access to Information and Privacy (ATIP) Office of the federal institution managing the proposed regulatory change.

You have the right to file a complaint to the Privacy Commission of Canada regarding any federal institution’s handling of your personal information.

The personal information provided is included in Personal Information Bank PSU 938 Outreach Activities. Individuals requesting access to their personal information under the Privacy Act should submit their request to the appropriate regulator with sufficient information for that federal institution to retrieve their personal information. For individuals who choose to submit comments anonymously, requests for their information may not be reasonably retrievable by the government institution.