Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector)

Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) Whereas, pursuant to subsection 332(1)a of the Canadian Environmental Protection Act, 1999b, the Minister of the Environment published in the Canada Gazette, Part I, on May 27, 2017, a copy of the proposed Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector), substantially in the annexed form, and persons were given an opportunity to file comments with respect to the proposed Regulations or to file a notice of objection requesting that a board of review be established and stating the reasons for the objection; Whereas, pursuant to subsection 93(3) of that Act, the National Advisory Committee has been given an opportunity to provide its advice under section 6c of that Act; And whereas, in accordance with subsection 93(4) of that Act, the Governor in Council is of the opinion that the proposed Regulations do not regulate an aspect of a substance that is regulated by or under any other Act of Parliament in a manner that provides, in the opinion of the Governor in Council, sufficient protection to the environment and human health; Therefore, Her Excellency the Governor General in Council, on the recommendation of the Minister of the Environment and the Minister of Health, pursuant to subsection 93(1), section 286.1d and subsection 330(3.2)e of the Canadian Environmental Protection Act, 1999b, makes the annexed Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector). S.C. 2004, c. 15, s. 31 S.C. 1999, c. 33 S.C. 2015, c. 3, par. 172(d) S.C. 2009, c. 14, s. 80 S.C. 2008, c. 31, s. 5 Protection of environment and reduction of harmful effects For the purpose of protecting the environment on which life depends and of reducing the immediate or long-term harmful effects of the emission of methane and certain volatile organic compounds on the environment or its biological diversity, these Regulations impose certain requirements on the oil and gas sector in order to reduce emissions of methane and certain volatile organic compounds; and designate the contravention of certain of its provisions as serious offences by adding them to the schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999). Definitions The following definitions apply in these Regulations. authorized official means in respect of an operator who is an individual, that individual or another individual who is authorized to act on their behalf; in respect of an operator that is a corporation, an officer of the corporation who is authorized to act on its behalf; and in respect of an operator that is another entity, an individual who is authorized to act on its behalf. (agent autorisé) combustion device means a device in which gaseous fuel is combusted to produce useful heat or energy. (appareil à combustion) completion means the process of making a well ready for production, including such a process that involves hydraulic fracturing. (complétion) deliver means to transport hydrocarbon gas from an upstream oil and gas facility for a purpose other than to dispose of the gas as waste. (livrer) design bleed rate means the rate, expressed in standard m3/h, at which gas is expected, according to the manufacturer of a pneumatic controller, to be continuously emitted from the pneumatic controller while it operates at a given operational setting specified by the manufacturer. (taux de purge nominal) destroy means to convert hydrocarbons contained in hydrocarbon gas to carbon dioxide and other molecules for a purpose other than to produce useful heat or energy, and includes the flaring of hydrocarbon gas. (détruire) Dominion Lands Survey system means the system for the survey of public lands referred to in sections 54 to 70 of the Dominion Lands Act, chapter 55 of the Revised Statutes of Canada, 1906 that is used in Manitoba, Saskatchewan and Alberta under the name the Dominion Lands Survey system. (système d’arpentage des terres fédérales) EPA Method 21 means the method of the Environmental Protection Agency of the United States entitled Method 21 — Determination of Volatile Organic Compound Leaks, set out in Appendix A-7 to Part 60 of Title 40, chapter I of the Code of Federal Regulations of the United States. (méthode 21 de l’EPA) equipment component means a component of equipment at an upstream oil and gas facility that comes into contact with hydrocarbons and that has the potential to emit fugitive emissions of hydrocarbon gas. (composant d’équipement) flowback means the process of recovering fluids, or fluids mixed with solids, that were injected into a well during hydraulic fracturing in order to prepare for further hydraulic fracturing; to prepare for cleanup of the well; or to initiate or resume production from the well. (reflux) fugitive, in relation to emissions of hydrocarbon gas, means the emission of hydrocarbon gas from an upstream oil and gas facility in an unintentional manner. (fugitive) gas-to-oil ratio means the ratio of the volume of hydrocarbon gas produced, expressed in standard m3, to the volume of hydrocarbon liquid produced, expressed in standard m3. (rapport gaz-pétrole) hydraulic fracturing means the process of injecting fluids, or fluids mixed with solids, under pressure into a well in order to create fractures in an underground geological reservoir through which hydrocarbons and other fluids can migrate toward the well and includes hydraulic refracturing, namely, hydraulic fracturing at a well that has previously undergone hydraulic fracturing. (fracturation hydraulique) hydrocarbon means methane, which has the molecular formula CH4, or a volatile organic compound referred to in item 60 of Part 2 of Schedule 1 to the Canadian Environmental Protection Act, 1999. (hydrocarbure) hydrocarbon gas conservation equipment means equipment used to recover hydrocarbon gas for use as fuel, for delivery or for injection for a purpose other than to dispose of the gas as waste into an underground geological deposit. (équipment de conservation de gaz d’hydrocarbures) legal subdivision means a unit of land consisting of one quarter of a quarter-section and having an area of approximately 16 ha or 400 m by 400 m that is described in the Dominion Lands Survey system. (subdivision officielle) natural gas gathering and boosting station means equipment that is located within a facility and that is used for the transportation of natural gas to a processing plant or natural gas transmission pipeline. (station de collecte et de surpression de gaz naturel) natural gas processing plant means a plant used for the separation of natural gas liquids (NGLs) or non-methane gases from produced natural gas; or NGLs into two or more mixtures, each of which consists of only those NGLs. (usine de traitement de gaz naturel) natural gas transmission compressor station means equipment that is located within a facility and that is used for the transportation of natural gas through a natural gas transmission pipeline. (station de compression de gaz naturel) operator means a person who has the charge, management or control of an upstream oil and gas facility. (exploitant) pneumatic controller means a device that uses pressurized gas to generate mechanical energy for the purpose of controlling or maintaining the conditions under which a process is carried out. (régulateur pneumatique) pneumatic pump means a device that uses pressurized gas to generate mechanical energy for the purpose of pumping liquid. (pompe pneumatique) ppmv means parts per million by volume. (ppmv) primary processing means any processing of hydrocarbons that is for the principal purpose of removing any of, or any combination of, the following: water; hydrocarbon liquids; sulphur compounds; and contaminants. (traitement primaire) produce, in relation to hydrocarbon gas or liquid, means to extract hydrocarbon gas or liquid from an underground geological deposit or reservoir. (produire) receive, in relation to hydrocarbon gas, means to receive at an upstream oil and gas facility, other than from a natural source, hydrocarbon gas that is raw or has undergone primary processing without having been subject to additional processing. (recevoir) standard conditions means a temperature of 15°C and a pressure of 101.325 kPa. (conditions normalisées) standard m3 means a cubic metre of fluid at standard conditions. (m3 normalisé) upstream oil and gas facility means the buildings, other structures and stationary equipment — that are located on a single site, on contiguous or adjacent sites or on sites that form a network in which a central processing site is connected by gathering pipelines with one or more well sites — for the purpose of the extraction of hydrocarbons from an underground geological deposit or reservoir; the primary processing of those hydrocarbons; or the transportation of hydrocarbons — including their storage for transportation purposes — other than for local distribution. It includes a gathering pipeline, transmission pipeline, natural gas gathering and boosting station, natural gas transmission compressor station and natural gas processing plant. (installation de pétrole et de gaz en amont) venting, in relation to emissions of hydrocarbon gas, means the emission of hydrocarbon gas from an upstream oil and gas facility in a controlled manner, other than the emission of gas arising from combustion, due to the design of equipment or operational procedures at the facility; or the occurrence of an event that pressurizes the gas beyond the capacity of the equipment at the facility to retain the gas. (évacuation) well includes a well drilled to allow for the injection of fluids or fluids mixed with solids. (puits) Interpretation of documents incorporated by reference For the purpose of interpreting any document that is incorporated by reference into these Regulations, “should” must be read to mean “must” and any recommendation or suggestion must be read as an obligation, unless the context requires otherwise. For greater certainty, the context of the accuracy or repeatability of a measurement can never require otherwise. Inconsistency In the event of an inconsistency between a provision of these Regulations and any document incorporated by reference into these Regulations, that provision prevails to the extent of the inconsistency. Documents incorporated by reference Any document that is incorporated by reference into these Regulations is incorporated as amended from time to time. Onshore facilities These Regulations apply in respect of upstream oil and gas facilities that are located onshore. Operator An operator for an upstream oil and gas facility must ensure that a requirement set out in these Regulations in respect of the facility or equipment at the facility — along with any related requirement in respect of recording information, keeping documents and providing reports — is complied with. [Repealed, SOR/2025-280, s. 4] Hydrocarbon gas conservation equipment Hydrocarbon gas conservation equipment that is used at an upstream oil and gas facility must be operated in such a manner that at least 95% of the hydrocarbon gas that is routed to the equipment — based on a calculation of the volumetric flow rates at standard conditions — is captured and conserved; be operating continuously, other than during periods when it is undergoing normal servicing or timely repairs; and be operated and maintained in accordance with the applicable recommendations of its manufacturer. Exception to paragraph (1)(c) Despite paragraph (1)(c), no recommendation referred to in that paragraph need be treated as a requirement and complied with if the operator for a facility has a record that establishes that without that compliance the hydrocarbon gas conservation equipment’s ability to respect paragraph (1)(a) is unaffected. Records — conservation equipment A record in respect of any hydrocarbon gas conservation equipment used at an upstream oil and gas facility must be made that indicates for each month during which the equipment is used, the percentage, at any given moment, of the hydrocarbon gas routed to the equipment that is captured and conserved, along with a calculation of the volumetric flow rates on which that percentage is based, with supporting documents; and how the equipment was operated and maintained, along with an indication of any recommendations of its manufacturer for its operation and maintenance, with supporting documents. Conserved gas — use Hydrocarbon gas that has been captured and conserved in hydrocarbon gas conservation equipment must be conserved until it is used at the facility as fuel in a combustion device that releases at most 5% of the combusted hydrocarbon gas to the atmosphere as hydrocarbon gas; delivered; or injected into an underground geological deposit for a purpose other than to dispose of the gas as waste. Records — conserved gas used as fuel A record in respect of any hydrocarbon gas that is combusted as fuel in a combustion device referred to in paragraph 7(a) must be made that indicates for each month during which the device is used, the percentage, at any given moment, of the combusted hydrocarbon gas that is released as hydrocarbon gas, with supporting documents, based on tests conducted when the device operates under conditions recommended by the manufacturer for determining this percentage; or measurements taken when the device operates under those conditions. Hydrocarbon gas destruction equipment Hydrocarbon gas destruction equipment that is used at an upstream oil and gas facility must satisfy the requirements related to the destruction of hydrocarbon gas set out in Sections 3.6 and 7 of Version 4.5 of the guideline entitled Flaring and Venting Reduction Guideline, published by the Oil and Gas Commission of British Columbia in June 2016, if the facility is located in British Columbia; section 3 of the directive entitled Directive S-20: Saskatchewan Upstream Flaring and Incineration Requirements, published by the Government of Saskatchewan on November 1, 2015, if the facility is located in Manitoba or Saskatchewan; and sections 3.6 and 7 of the directive entitled Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting, published by the Alberta Energy Regulator on March 22, 2016, in any other case. Records — hydrocarbon gas destruction equipment A record in respect of any hydrocarbon gas destruction equipment used at an upstream oil and gas facility must be made that demonstrates, with supporting documents, that the requirements related to the destruction of hydrocarbon gas set out in the applicable document referred to in section 9 are satisfied. Application This section applies in respect of an upstream oil and gas facility that includes a well that undergoes hydraulic fracturing and whose production has a gas-to-oil ratio of at least 53:1, based on the most recent determination of the gas-to-oil ratio prior to the hydraulic fracturing. No venting Hydrocarbon gas associated with flowback at a well at an upstream oil and gas facility must not be vented during flowback but must instead be captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment. Exception Subsection (2) does not apply if all the gas associated with flowback at the well does not have sufficient heating value to sustain combustion. Records — hydraulic fracturing A record in respect of each well at an upstream oil and gas facility that undergoes hydraulic fracturing must be made that indicates the gas-to-oil ratio, based on the most recent determination of the gas-to-oil ratio prior to the hydraulic fracturing; if that gas-to-oil ratio is at least 53:1, that demonstrates, with supporting documents, that the hydrocarbon gas associated with flowback was captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment; and if hydrocarbon gas associated with flowback at the well is vented, the heating value of that gas. Non-application — British Columbia and Alberta Sections 11 and 12 do not apply in respect of an upstream oil and gas facility that is located in British Columbia, if the facility is subject to the requirements with respect to well completion involving hydraulic fracturing that are set out in the guideline entitled Flaring and Venting Reduction Guideline, published by the Oil and Gas Commission of British Columbia in June 2016; and Alberta, if the facility is subject to the requirements with respect to well completion involving hydraulic fracturing that are set out in the directive entitled Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting, published by the Alberta Energy Regulator on March 22, 2016. Capture or venting of emissions The emissions of hydrocarbon gas from the seals of a centrifugal compressor, or from the rod packings and distance pieces of a reciprocating compressor, that has a rated brake power of 75 kW or more at an upstream oil and gas facility must be captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment; or routed to vents that release those emissions to the atmosphere. Measurement of flow rate The flow rate of emissions of hydrocarbon gas released from the vents referred to in paragraph 14(b) of a compressor must be measured by means of a flow meter, other than a calibrated bag, in accordance with section 16; or a continuous monitoring device in accordance with section 17. Flow meters The flow meter must be calibrated in accordance with the manufacturer’s recommendations such that its measurements have a maximum margin of error of ±10%. Measurements by flow meters Those measurements must be made in accordance with the recommendations set out in the manufacturer’s manual, if any; in the case of a measurement made without the use of negative pressure or a vacuum, while there is a tight seal over the vent; in the case of a measurement on a centrifugal compressor, when the compressor is operating under conditions that are representative of the conditions during the previous seven days; and in the case of a measurement on a reciprocating compressor, when the compressor is pressurized. Initial and subsequent measurements The flow rate must be measured within the following periods: initially, the period that ends on January 1, 2021, if the compressor is installed at the facility before January 1, 2020, and the 365th day after the day on which the compressor was installed at the facility, in any other case; and subsequently, the period that ends on the 365th day after the day on which a previous measurement was taken. Measurements — maximum or average The initial and each subsequent measurement of the flow rate must be based on measurements made by the flow meter over a continuous period of at least five minutes and is the maximum of the flow rates measured, if the measurements are made over a continuous period of at least five minutes and less than 15 minutes; or the average of the flow rates measured, if the measurements are made over a continuous period of at least 15 minutes. Extension — not operating or not pressurized Despite subsection (3), if no measurement has been made by the last day of a period referred to in that subsection — but, on that day, the compressor is not operating, in the case of a centrifugal compressor, or the compressor is not pressurized, in the case of a reciprocating compressor — the measurement must be made under that subsection on or before the 30th day after the day on which the compressor is next operating or pressurized, as the case may be. Extension — pressurized for < 1,314 hours per 3 years Despite subsection (3), a period referred to in that subsection is extended by 365 days if the operator for the facility makes a record that demonstrates that, during the three calendar years immediately before the end of the period, the compressor was pressurized for less than 1,314 hours, as determined by an hour meter or as recorded in a log of operations. Continuous monitoring devices A continuous monitoring device must be calibrated in accordance with the recommendations of the manufacturer of the device such that its measurements have a maximum margin of error of ±10%; be operated continuously, other than during periods when it is undergoing normal servicing or timely repairs; and be equipped with an alarm that is triggered when the applicable flow rate limit referred to in subsection 18(2) or (3) for the vents of the compressor is reached. Corrective action If the flow rate of emissions of hydrocarbon gas released from vents referred to in paragraph 14(b) of a compressor, measured in accordance with subsection 16(2), is greater than the applicable flow rate limit set out in subsection (2) or (3) or if the alarm referred to in paragraph 17(c) is triggered, corrective action must be taken to reduce that flow rate to below or equal to that limit, as demonstrated by a remeasurement that results, when a flow meter is used for the remeasurement, in a reading that is below or equal to that limit; or when a continuous monitoring device is used for the remeasurement, in the absence of an alarm when the compressor resumes operation following the taking of the corrective action. Flow rate limit — centrifugal compressors For emissions that are from the seals of a centrifugal compressor, the flow rate limit is if the compressor is installed on or after January 1, 2023, 0.14 standard m3/min; and if the compressor is installed before January 1, 2023 and has a rated brake power of greater than or equal to 5 MW, 0.68 standard m3/min, and less than 5 MW, 0.34 standard m3/min. Flow rate limit — reciprocating compressors For emissions that are from the rod packings and distance pieces of a reciprocating compressor, the flow rate limit is if the compressor is installed on or after January 1, 2023, the product of 0.001 standard m3/min and the number of pressurized cylinders that the compressor has; and if the compressor is installed before January 1, 2023, the product of 0.023 standard m3/min and the number of those pressurized cylinders. Remeasurement The remeasurement referred to in paragraph (1)(a) or (b) must be taken in accordance with section 15 on or before the later of the 90th day after the day on which, as the case may be, the most recent measurement is taken under subsection 16(3) or the alarm referred to in paragraph 17(c) is triggered, and if the estimated volume of hydrocarbon gas, expressed in standard m3, that would, beginning from the day on which the applicable day described in paragraph (a), be emitted until that next planned shutdown if no corrective action were taken is equal to or less than the volume of hydrocarbon gas, expressed in standard m3, that would be emitted due to the purging of hydrocarbon gas in order to take the corrective action, the day on which the compressor begins to operate after the next planned shutdown, in the case of a centrifugal compressor, and the day on which the compressor is first pressurized after the next planned shutdown, in the case of a reciprocating compressor. Estimated volume The estimated volume of hydrocarbon gas must be based on the most recent flow rate of emissions of hydrocarbon gas released from vents referred to in paragraph 14(b) of the compressor, as determined by a flow meter or a continuous monitoring system in accordance with section 15. Records — compressors and vents A record must be made that indicates for each compressor referred to in section 14 its serial number; its make and model; its rated brake power; the date on which it was installed at the facility, if it was installed on or after January 1, 2020, or a demonstration, with supporting documents, that it was installed at the facility before January 1, 2020; if applicable, the type of hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment to which the emissions of hydrocarbon gas from the its seals or rod packing and distance pieces, as the case may be, are captured and routed, namely a vapour recovery unit, a vent gas capture system, a flare, an enclosed combustor, or another type, and if so, a description of the type; for each centrifugal compressor for which emissions from its seals are routed to vents that release those emissions to the atmosphere, whether the seals are dry or wet; for each reciprocating compressor from which emissions from its rod packings and distance pieces are routed to vents that release those emissions to the atmosphere, the number of those rod packings; and for each compressor for which the period within which a measurement by a flow meter must be made has been extended under subsection 16(6), the number of hours during which it was pressurized during the three calendar years referred to in that subsection. Records — flow meters A record must be made that indicates, for each measurement, including a remeasurement, the flow rate of emissions from a vent referred to in paragraph 14(b) made by means of a flow meter referred to in paragraph 15(a), the make and model of the flow meter; the maximum flow rate referred to in paragraph 16(4)(a) or the average flow rate referred to in paragraph 16(4)(b), as the case may be; the date on which the measurement was taken; the recommendations of the manufacturer for the calibration of the flow meter referred to in subsection 16(1), along with a demonstration, with supporting documents, that the measurements taken with that calibration have a maximum margin of error of ±10%; any recommendation for the taking of the measurement, along with supporting documents; the duration of the continuous period referred to in paragraph 16(4)(a) or (b), as the case may be; and the name of the person who took the measurement and, if that person is a corporation, the name of the individual who took it. Records — continuous monitoring devices A record must be made that indicates, for each measurement, including a remeasurement, of the flow rate of emissions from a vent referred to in paragraph 14(b) made by means of a continuous monitoring device referred to in paragraph 15(b), a description of the device; if applicable, its serial number, make and model; and the recommendations of the manufacturer for the calibration of the continuous monitoring device referred to in paragraph 17(a) along with a demonstration, with supporting documents, that the measurements taken with that calibration have a maximum margin of error of ±10%. Records — corrective actions taken A record must be made that indicates, for each corrective action taken, a description of the corrective action, including a description of each step of the corrective action; the dates on which that corrective action was taken, along with the dates on which each of its steps was taken; for each remeasurement taken under paragraph 18(4)(b), the volume and estimated volume, determined for the purpose of that paragraph, along with supporting calculations; and if the corrective action was taken as a result of a measurement by means of a continuous monitoring device, the date on which the alarm was triggered. Application of sections 26 to 45 Sections 26 to 45 apply in respect of an upstream oil and gas facility as of the first day of the month that begins after the facility produces or receives — or is expected to produce or receive — a combined volume of more than 60 000 standard m3 of hydrocarbon gas for a period of 12 months, determined as follows: if the facility has operated during at least 12 months, whether consecutive or not, with at least one day of operation in each of those months, the combined volume of hydrocarbon gas, expressed in standard m3, produced or received based on records, for the most recent 12 of those months of operation; if the facility has operated during at least one month and less than 12 months, whether consecutive or not, with at least one day of operation in each of those months, the combined volume of hydrocarbon gas, expressed in standard m3, that the facility is expected to produce or receive for a 12-month period determined by prorating the combined volume, based on records, produced or received during those months of operation; and in any other case, the combined volume of hydrocarbon gas, expressed in standard m3, that the facility is expected to produce or receive during the 12-month period that begins after its first month of operation, as determined in accordance with the applicable method set out in section 23. Well completion For the purpose of subsection (1), if a well at the facility undergoes well completion during a given month, the portion of the combined volume referred to in that subsection that corresponds to the production of hydrocarbon gas from the well must be based on the volume of hydrocarbon gas expected to be produced by the well for the 12-month period after the given month, as determined in accordance with the applicable method set out in section 23. Records — non-application If none of sections 26 to 45 apply, for a given month, in respect of an upstream oil and gas facility, a record, with supporting documents, must be made that indicates the gas-to-oil ratio and the volume of the hydrocarbon liquid produced or expected to be produced, expressed in standard m3, during the given month; the combined volume of hydrocarbon gas produced and received, expressed in standard m3, during the given month; and for a well at the facility that undergoes well completion during the given month, the volume expected to be produced by the well referred to in subsection 20(2). Records — application A record must be made that indicates the following information for the first month that begins after the facility produces or receives — or is expected to produce or receive — a combined volume of more than 60 000 standard m3 of hydrocarbon gas for a period of 12 months as determined in accordance with subsection 20(1): that first month and the calendar year that includes that first month; and the combined volume, along with an indication as to which of paragraphs 20(1)(a) to (c) was used to determine that volume. Applicable methods For the purpose of sections 20 and 26, the volume of hydrocarbon gas produced, received, vented or destroyed at, or delivered from, an upstream oil and gas facility must be determined in accordance with the applicable method set out in the document entitled Measurement Guideline for Upstream Oil and Gas Operations, published by the Oil and Gas Commission of British Columbia on March 1, 2017, if the facility is located in British Columbia; the document entitled Measurement Requirements for Oil and Gas Operations and commonly referred to as Directive PNG017, published by the Government of Saskatchewan on August 1, 2017 (version 2.1), if the facility is located in Manitoba or Saskatchewan; and the document entitled Measurement Requirements for Oil and Gas Operations and commonly referred to as AER Directive 017, published by the Alberta Energy Regulator on March 31, 2016, in any other case. Directive PNG017 and AER 017 Despite paragraphs (1)(b) and (c), for the purpose of sections 12.2.2.1 and 12.2.2.2 of the Saskatchewan Directive PNG017 and of the AER Directive 017, the gas production per well per day is to be determined if the expected gas production is greater than 2 000 standard m3 per day, by direct measurement; and in any other case, by direct measurement, or by means of an estimate based on a gas-to-oil ratio determined in accordance with section 24, or by the formula is the average volume, expressed in standard m3, of oil produced by the well for a day during the most recent month of production. Determination of gas-to-oil ratio The determination of a gas-to-oil ratio for the purpose of clause 23(2)(b)(ii)(A) is made using the formula is the average volume of gas produced by the well measured over a continuous period — of at least 72 hours or at least 24 hours, determined, as the case may be, in accordance with subsection (2) or (3) — under conditions, in particular in respect of flow rate and operating conditions, that are representative of the conditions that occurred during the most recent month of production; and is the average volume of oil produced by the well over the period that is used for the determination of G, based on measurements taken in accordance with subsection (4) as prorated to that period and under conditions, in particular in respect of flow rate and operating conditions, that are representative of the conditions during the most recent month of production. Determination of value of G The measurements to determine the value of G must be taken over a continuous period of at least 72 hours with a continuous measuring device or using a flow meter with at least one reading taken every 20 minutes. Despite subsection (2), the measurements to determine the value of G may be taken over a continuous period of at least 24 hours, if the flow rate of gas from the well is greater than 100 standard m3 per day; and the measurement is taken with a continuous measuring device and the variation of flow rate in that continuous period is such that the average flow rate for any 20-minute period is within ±5% of the average flow rate, or using a flow meter with at least one reading taken every 20 minutes within that continuous period and the variation of flow rate in that continuous period is such that 95% of the readings taken are within ±5% of the average flow rate. Determination of the value of O The measurements to determine the value of O must be taken after the water has been separated from the liquid produced from the well and taken over the continuous period used to determine the value of G with a continuous measuring device that has a maximum margin of error of ±0.1 standard m3; or over a continuous period of at least 10 days that includes the continuous period used to measure G with a continuous measuring device that has a maximum margin of error of ±1 standard m3 and with the variation of flow rate in that continuous period such that the measured volume of oil produced for any day is within ±5% of the measured volume of oil produced for any other day in that continuous period. Steady state A measurement taken under any of subsections (2) to (4) must be taken while the well is operating in a steady state, that is, it must be taken only if no adjustment that could result in a change to the oil or gas production rates has been made to the production parameters for at least 48 hours before the measurement is taken. Measuring equipment — directives The continuous measuring device or flow meter used to determine the gas-to-oil ratio must meet the requirements of section 2 of the Saskatchewan Directive PNG017 or section 2 of the AER Directive 017. Frequency of determination A determination of the gas-to-oil ratio must be made at least once per year and at least 90 days after a previous determination, if in the case of an initial determination, the expected flow rate of the gas is at most 500 standard m3 per day, and in any other case, the flow rate of the gas according to the most recent determination was at most 500 standard m3 per day; at least once every six months and at least 45 days after a previous determination, if in the case of an initial determination, the expected flow rate of the gas is greater than 500 standard m3 per day and at most 1 000 standard m3 per day, and in any other case, the flow rate of the gas according to the most recent determination was greater than 500 standard m3 per day and at most 1 000 standard m3 per day; and at least once every month and at least seven days after a previous determination, if in the case of an initial determination, the expected flow rate of the gas is greater than 1 000 standard m3 per day and at most 2 000 standard m3 per day, and in any other case, the flow rate of the gas according to the most recent determination was greater than 1 000 standard m3 per day and at most 2 000 standard m3 per day. Records A record must be made that indicates all of the readings from a continuous measuring device and each reading taken using a flow meter; the flow rate over each period during which measurements were taken for each determination of the value of G and O; the dates, time and duration of each of those periods; the production parameters during each of those periods and the 48 hours before each of those periods begins; and whether the type of equipment used to take each measurement was a continuous measuring device or a flow meter and its make and model. 15 000 standard m3 per year An upstream oil and gas facility must not vent more than 15 000 standard m3 of hydrocarbon gas during a year. Excluded volumes The volumes of hydrocarbon gas vented that arose from the following activities are excluded from the determination of the volume vented for the purpose of subsection (1): liquids unloading, that is, the removal of accumulated liquids from a gas well; a blowdown, that is, the temporary depressurization of equipment or pipelines; glycol dehydration, that is, the use of a liquid desiccant system to remove water from natural gas or natural gas liquids; the use of a pneumatic controller, pneumatic pump or compressor; the start-up and shutdown of equipment; well completion; and venting in order to avoid serious risk to human health or safety arising from an emergency situation. Non-application of subsection (1) Subsection (1) does not apply in respect of a facility, as of a given month, if the combined volume of hydrocarbon gas that was vented or destroyed at, or delivered from, the facility was less than 40 000 standard m3 for the 12 consecutive months before that given month. Re-application of subsection (1) Despite subsection (3), subsection (1) does apply in respect of a facility referred to in subsection (3), as of a subsequent month, if the combined volume of hydrocarbon gas that was vented or destroyed at, or delivered from, the facility was equal to or greater than 40 000 standard m3 for the 12 consecutive months before that subsequent month. Records — volumes of hydrocarbon gas For each month that an upstream oil and gas facility operates, a record, with supporting documents, must be made that indicates the volume of hydrocarbon gas that was vented, expressed in standard m3; the volume of hydrocarbon gas vented that arose from the activities referred to in each of paragraphs 26(2)(a) to (g); the volume of hydrocarbon gas destroyed at the facility, expressed in standard m3; and the volume of hydrocarbon gas delivered from the facility, expressed in standard m3. Non-application to certain equipment components Sections 29 to 36 do not apply in respect of an equipment component used on a wellhead at a site at which there is no other wellhead or equipment except for gathering pipelines or a meter connected to the wellhead; a pair of isolation valves on a transmission pipeline if no other equipment is located on the segment of the pipeline that may be isolated by closing the valves; and an equipment component used at an upstream oil and gas facility whose inspection would pose a serious risk to human health or safety. Record A record must be made that indicates whether an equipment component is an equipment component referred to in any of paragraphs (1)(a) to (c). Regulatory or alternative LDAR programs An operator for a facility must — in order to limit fugitive emissions containing hydrocarbon gas from equipment components at the facility — establish and carry out at the facility a regulatory leak detection and repair program that satisfies the requirements of sections 30 to 33; or an alternative leak detection and repair program referred to in subsection 35(1) that results in at most the same quantity of those fugitive emissions as would result from a regulatory program referred to in paragraph (a), as demonstrated in a record, with supporting documents, made by the operator before the program is established and, at least once per year and at least 90 days after a previous demonstration, while the program is being carried out. Notice to Minister An operator for a facility that establishes a leak detection and repair program referred to in paragraph (1)(b) must, without delay, notify the Minister to that effect. Obligation to inspect An equipment component at an upstream oil and gas facility must be inspected, during the periods referred to in subsection (3), for the release of hydrocarbons by means of an eligible leak detection instrument. Eligible leak detection instruments The following leak detection instruments are eligible: a portable monitoring instrument if it meets the specifications set out in Section 6 of EPA Method 21, is operated in accordance with the requirements of Section 8.3 of EPA Method 21 to the extent that those requirements are consistent with its manufacturer’s recommendations, is calibrated in accordance with Sections 7, 8.1, 8.2 and 10 of EPA Method 21 before it is used, for each day on which it is used, and undergoes a calibration drift assessment after its last use on each of those days in accordance with the requirements set out in Section 60.485a(b)(2) of Subpart VVa, entitled Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for which Construction, Reconstruction, or Modification Commenced After November 7, 2006, in Part 60 of Title 40, Chapter I of the Code of Federal Regulations of the United States; and an optical gas-imaging instrument if it is capable of imaging gas that is in the spectral range for the compound of highest concentration in the hydrocarbon gas to be measured, half methane and half propane at a total concentration of at most 500 ppmv and at a flow rate of at least 60 g/h leaking from an orifice that is 0.635 cm in diameter, and at the viewing distance determined in accordance with the requirements of the alternative work practice of the Environmental Protection Agency of the United States set out in Sections 60.18(h)(7)(i)(2)(i) to (v) of Section 60.18, entitled General control device and work practice requirements, in Part 60 of Title 40, Chapter I of the Code of Federal Regulations of the United States. Period for inspections The period for inspections is as follows: for the first inspection, on or before the later of May 1, 2020 and the day that occurs 60 days after the day on which production at the facility first began; and for subsequent inspections, at least three times per year and at least 60 days after a previous inspection. Operation and maintenance An eligible leak detection instrument must be operated and maintained in accordance with the recommendations, if any, of its manufacturer. Training The inspection must be conducted by an individual who, not more than five years before the inspection, has received training in the operation and maintenance, in accordance with subsection (4), of eligible leak detection instruments; and the calibration requirements set out in subparagraphs (2)(a)(iii) and (iv), if an eligible portable monitoring instrument is used. Leaks A release of hydrocarbons from an equipment component is a leak if the release consists of at least 500 ppmv of hydrocarbons, as determined by an inspection conducted by means of an eligible portable monitoring instrument in accordance with EPA Method 21; or the release is detected during an inspection conducted by means of an eligible optical gas-imaging instrument, or by means of an auditory method, an olfactory method or a visual method, including the observation of the dripping of hydrocarbon liquids from the equipment component. Release not considered a leak A release that is detected under paragraph (1)(b) is no longer considered to be a leak if the equipment component undergoes an inspection conducted by means of an eligible portable monitoring instrument in accordance with EPA Method 21 and the release is determined to consist of less than 500 ppmv of hydrocarbons. Period for repair A leak from an equipment component that is detected, whether as a result of an inspection or otherwise, must be repaired if the repair can be carried out while the equipment component is operating, within 30 days after the day on which it was detected; and in any other case, within the period before the end of the next planned shutdown unless that period is extended under section 33. Next planned shutdown The next planned shutdown must be scheduled not later than the date on which the estimated volume of hydrocarbon gas, expressed in standard m3, that, beginning from the day on which the leak is detected, would if no repairs are made be emitted from the leaking equipment component in question and from all other equipment components that are also leaking as of that day is equal to the volume of hydrocarbon gas, expressed in standard m3, that would be emitted due to purging of hydrocarbon gas from equipment components in order to carry out the repair. Repair A leak in an equipment component is considered to be repaired if the release is determined to consist of less than 500 ppmv of hydrocarbons based on an inspection of the equipment component by means of an eligible portable monitoring instrument in accordance with EPA Method 21 that is capable of measuring hydrocarbon concentrations in ppmv. Extension up to six months for repair An operator for an upstream oil and gas facility that must repair an equipment component on or before the end of a period referred to in paragraph 32(1)(b) may, not later than 45 days before the end of the period, apply to the Minister to extend the period for up to six months. Granting of extension The Minister must grant the application and extend the period for up to six months if the application contains the information set out in Schedule 1 and documents that establish that, as of the making of the application, there are reasonable grounds to conclude that it is not technically feasible to complete the repair of the equipment component before the end of the next planned shutdown; documents that establish that the applicant has a plan to repair the equipment component that sets out the expected date for the completion of the repair, the steps to be taken to ensure completion of the repair on or before that date, a justification, with supporting documents, for the belief that that date is the earliest feasible date to complete the repair, and measures to be taken to minimize, if not eliminate, any harmful effect on the environment or human health from the emission of hydrocarbon gas before the completion of the repair; and a statement that the implementation of the plan is to begin within 30 days after the day on which the extension is granted. Renewal The period granted under subsection (2) may be further extended by application made under subsection (1). At most two applications for a further extension may be made. Refusal of application The Minister must refuse the application if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in the application. Revocation of extension The Minister must revoke the extension granted under subsection 33(2) if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in their application for the extension. Conditions for revocation The Minister must not revoke the extension unless the Minister has provided the applicant with written reasons for the proposed revocation; and an opportunity to be heard, by written representation, in respect of the proposed revocation.

Requirements for alternative program The alternative leak detection and repair program must include measures respecting the inspection for leaks; the operation, maintenance and calibration of leak detection instruments, if applicable; and the repair of leaks detected. Reversion to regulatory program An operator for a facility that has not made a demonstration required by paragraph 29(1)(b) must establish and carry out a regulatory leak detection and repair program. Regulatory LDAR programs A record, with supporting documents, must be made of the following information related to the carrying out of a regulatory leak detection and repair program: for each calibration of an eligible leak detection instrument, the dates of the calibration, the result of each calibration drift assessment, and the name, job title, if any, and address of the individual who carried out the calibration; for each inspection of an equipment component, the date of the inspection, along with the name of the individual who conducted it, the type of equipment component, the location of the equipment component within the facility or the Global Positioning System (GPS) coordinates, to five decimal places, of the equipment component, the type of leak detection instrument used to conduct the inspection, including, if any, its make and model, in the case that an optical gas-imaging instrument referred to in subparagraph 31(1)(b)(i) was used to conduct the inspection, the images recorded with an embedded indication of the date and time when they were recorded, along with the location of the place where they were recorded within the facility or the GPS coordinates, to five decimal places, of the place, and in the case that an inspection resulted in the detection of a leak, an indication of the means, among those set out in subsection 31(1), by which the leak was detected and, in the case of a leak detected by a means set out in paragraph 31(1)(b), an indication as to whether the release was determined in accordance with subsection 31(2) to consist of less than 500 ppmv and, if so, the date of that determination, the name of the person who made that determination — and if that person is a corporation, the name of the individual who made it — and its result, expressed in ppmv, along with the make and model, if any, of the instrument used to make that determination; for each leak detected by means of a method set out in paragraph 31(1)(b) that was not as a result of an inspection, an indication of whether the method was auditory, olfactory or visual, the date on which the leak was detected, along with the name of the individual who detected it, the location of the equipment component within the facility or its GPS coordinates, to five decimal places, and an indication as to whether the release was determined in accordance with subsection 31(2) to consist of less than 500 ppmv and, if so, the date of that determination, the name of the person who made that determination — and if that person is a corporation, the name of the individual who made it — and its result, expressed in ppmv, along with the make and model, if any, of the instrument used to make that determination; for each individual who conducted an inspection and who received training in the operation and maintenance or in the calibration of leak detection instruments, their name, along with the name and business address of their employer, if their employer is not the operator, the name and business address of the entity that provided the training, along with the name and job title of the individuals who provided it, the dates on which the training was provided and, for each of those dates, the number of hours of training, and a description of the training; for each repair of a leak from an equipment component, a description of the steps that were taken to repair the leak, along with the dates on which those steps were taken, and the result, expressed in ppmv, obtained following an inspection by means of an eligible portable monitoring system in accordance with EPA Method 21, along with the date on which that result was obtained; and for each repair that was not carried out within 30 days after the detection of the leak: an indication as to why the equipment component could not be repaired while it was operating, and if applicable, the date determined in accordance with subsection 32(2), along with the information and calculation on which that determination was based. Alternative LDAR programs A record, with supporting documents, must be made of the following information related to the carrying out of an alternative leak detection and repair program: the date on which each inspection was conducted and, if applicable, the name of the person who conducted it; the type of equipment component that was inspected, along with its location within the facility or its GPS coordinates, to five decimal places; a description as to the means by which the leak was identified; if applicable, for each leak detection instrument used, a description of the operation, maintenance and calibration measures in relation to that instrument, along with the dates of its maintenance and calibrations and the names of the persons who carried out the maintenance and calibrations; the result obtained after the repair following an inspection, along with a description of the means by which that inspection was conducted, its date and, if applicable, the name of the person who conducted it; and the demonstrations referred to in paragraph 29(1)(b). Document-keeping A copy of each recommendation of the manufacturer for the operation and maintenance, if any, of each eligible leak detection instrument that is used must be kept. Pneumatic controllers — bleed rate A pneumatic controller at an upstream oil and gas facility must not operate using hydrocarbon gas, other than propane, unless it is operated at an operational setting such that its bleed rate for that operational setting is less than or equal to 0.17 standard m3/h according to the manufacturer’s operating manual or according to a written demonstration, with supporting documents, made by the operator for the facility; or the hydrocarbon emissions from it are captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment. Exception — control of production processes Despite paragraph (1)(a), a pneumatic controller at an upstream oil and gas facility may operate using hydrocarbon gas, other than propane, at an operational setting such that its bleed rate for that operational setting is more than 0.17 standard m3/h if the operator for the facility has a written record, with supporting documents, that demonstrates that the pneumatic controller must operate at that operational setting because of the need for the pneumatic controller to have a sufficient response time to control a process in the facility’s production activities. Records — pneumatic controllers A record in respect of each pneumatic controller used at an upstream oil and gas facility that operates using hydrocarbon gas must be made that indicates the identifier for the pneumatic controller; whether the pneumatic controller is used for controlling pressure or flow rate, for controlling liquid levels, for controlling temperature, as a transducer, as a positioner, or as an emergency response device, or for another purpose or as another device and, if so, the purpose or type of device; and the design bleed rate for the pneumatic controller’s operational setting, including its supply pressure and, if any, its band setting, or its bleed rate according to a written demonstration, with supporting documents, made by the operator for the facility at which the controller is used. Pneumatic pumps Unless an operator for an upstream oil and gas facility has a permit issued in accordance with subsection 40(2), a pneumatic pump or a group of pneumatic pumps, used at the facility that pumps methanol into a common stream or an equipment component — must not operate using hydrocarbon gas if the pump or the group of pumps has, in a month, pumped more than 20 L of methanol per day on average over the month. Demonstration of quantity of liquid pumped An operator for the facility must, for each pump or group of pumps referred to in subsection (1) that operates during a month at the facility, demonstrate the quantity of liquids that it pumped, on average, per day over the month by means of a record that indicates the quantity of liquid pumped during that month; or documents that establish that the pump or the group of pumps could not have pumped more than 20 L of liquid per day on average over the month. When subsection (2) no longer applies Subsection (2) no longer applies in respect of a pump or group of pumps as of the end of a month during which it operated at the facility and records establish that it pumped, or could have pumped, more than 20 L of liquid per day on average over the month. Non-application of subsections (1) and (2) Subsections (1) and (2) do not apply in respect of any pneumatic pump if hydrocarbon emissions from it are captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment. Permit — pneumatic pumps An operator for an upstream oil and gas facility may, on or before June 30, 2022, apply to the Minister for a permit to have a pneumatic pump at the facility operate using hydrocarbon gas while its hydrocarbon emissions are not captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment. Issuance of permit The Minister must issue the permit if the application contains the information set out in Schedule 2 and documents that establish that there are reasonable grounds to conclude that it is not feasible, technically or economically, for the applicant to have the pneumatic pump operate at the facility without using hydrocarbon gas or to have the pneumatic pump function using hydrocarbon gas while its hydrocarbon emissions are captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment, including grounds based on the capital, operating and maintenance costs of any modifications at the facility to achieve that objective, and the avoided costs and any economic benefits arising from the incurring of those capital, operating and maintenance costs; and the applicant has a plan that involves taking steps to minimize the emission of hydrocarbon gas from the pneumatic pump, including steps such as adjusting the capacity of the pump or its operational settings so as to achieve the desired rate of injection of chemicals from the pump with the least possible emissions, along with a schedule to implement the plan, and can reasonably be regarded as feasible for the purpose of permitting the facility to comply with subsection 39(1) on or before January 1, 2026. Duration A permit takes effect on January 1, 2023 and expires on the earliest of the day on which the pneumatic pump ceases to function using hydrocarbon gas, the day on which the hydrocarbon emissions from the pneumatic pump begin to be captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment, and December 31, 2025. Tagging A pneumatic controller that is referred to in subsection 37(2) or a pneumatic pump referred to in a permit issued under subsection 40(2) must be tagged to indicate that it is not subject to subsection 37(1) or 39(1) or an entry to that effect must be made in an electronic tracking system. Identifier The tag or the entry must also include an identifier for the pneumatic controller or the pneumatic pump. Pipes and hatches A hatch and the open end of a pipe at an upstream oil and gas facility must be closed — other than during an operation at the facility that requires the hatch or pipe to be open — in such a way as to minimize the emission of hydrocarbon gas. Sampling systems and pressure relief devices A sampling system or a pressure relief device used at an upstream oil and gas facility must be installed and operated in such a way as to minimize the emission of hydrocarbon gas from the system or the pressure relief device. Records — hatches, pipes, systems and devices A record must be made that indicates whether an upstream oil and gas facility has a hatch, a pipe with an open end or uses a sampling system or pressure relief device. Subsection 40(2) The Minister must revoke a permit issued under subsection 40(2) if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in their application for the permit. The Minister must not revoke a permit unless the Minister has provided the applicant with [Repealed, SOR/2025-280, s. 15] Registration report An upstream oil and gas facility in respect of which any of sections 5, 9, 11, 14 and 15 apply or in respect of which sections 26 to 45 apply and an offshore facility in respect of which section 46 applies must be registered by providing the Minister with a registration report for the facility that contains the information set out in Schedule 3. Date of registration The facility must be registered not later than 120 days after the later of January 1, 2020, and the earlier of the first day on which any of sections 5, 9, 11, 14, 15 and 46 apply in respect of the facility, and the first day of the month referred to in subsection 20(1) as of which sections 26 to 45 apply in respect of the facility. Updated information If there is a change such that the information provided in the facility’s registration report is no longer accurate, a notice to that effect that contains the updated information, along with the information referred to in item 4 of Schedule 3, must be sent to the Minister not later than 90 days after the change. Provision of information Information that is required under section 54 to be in a registration report provided to the Minister may be provided to the Minister via an approved entity. Deemed provision of registration report If all of the information required to be in a registration report is provided to the Minister via an approved entity, the operator for that facility must notify the Minister to that effect. The registration report is deemed to have been provided to the Minister on the day on which the Minister receives that notice. Approval of entity The Minister may approve an entity for the purpose of subsection (1) if the Minister concludes an arrangement with the entity under which information referred to in section 54 that is provided to the entity is accessible to the Minister. Publication of approved entities The Minister must publish a list of approved entities in the Environmental Registry established under section 12 of the Canadian Environmental Protection Act, 1999. Withdrawal of approval The Minister may withdraw the approval of an entity and publish a notice to that effect in the Environmental Registry. Record-making and updates A record that is required to be made under these Regulations must be made within 30 days after the day on which the information to be recorded becomes available. The record must be updated within 30 days after the information to be updated becomes available. Record-keeping — indefinite A record, along with supporting documents, of information that applies on an ongoing basis must be kept indefinitely until an update is required. Record-keeping — five years If an update referred to in subsection (2) is required, the record of the information, along with its supporting documents, as recorded before the updating must be kept for five years after the updating. A record, along with supporting documents, of information that applies only in respect of a given day, must be kept for five years after that given day. A document that is required to be kept under these Regulations must be kept for five years. Place kept The records and documents must be kept at the upstream oil and gas facility to which they relate or at another place in Canada where they can be inspected. Provision of records On the Minister’s request, the operator must, within 60 days after the day on which the request was made, provide any of the records or documents kept to the Minister. [Amendment] January 1, 2020 Subject to subsection (2), these Regulations come into force on January 1, 2020. January 1, 2023 Sections 26, 27 and 37 to 41 of these Regulations and paragraphs 30(p), (q), (v), (w) and (x) of the schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999), as enacted by section 57 of these Regulations, come into force on January 1, 2023. The name and civic address of the operator. The name, job title, civic and postal addresses, telephone number and email address of the operator’s authorized official. The name, job title, civic and postal addresses, telephone number and email address of a contact person, if different from the authorized official. The name of the facility and the federal and provincial identification numbers for the facility, if any, and its civic address or, if the civic address is not available, its latitude and longitude to the third decimal place; its location expressed to the nearest unit of the National Topographic System produced by the Department of Natural Resources; or the legal subdivision within which the facility is located, if it is located in Manitoba, Saskatchewan or Alberta. The date on which the next planned shutdown of the facility is to end. The following information in respect of the equipment component for which the extension to the period by which it must be repaired is applied for: the identifier for the equipment component, along with its make and model, if that information is available; the name of its manufacturer, along with the manufacturing location; a description of the equipment component, including an explanation of its functions within the production processes of the facility and how those functions are carried out; and any other information that is relevant to determine whether it is technically feasible to complete the repair of the equipment component before the end of the next planned shutdown. The identifier for the pneumatic pump, along with its make and model and the name of its manufacturer, if that information is available. The name of the facility, all provincial identification numbers that are related to the facility and used for reporting to provincial authorities, along with the facility’s civic address or, if the civic address is not available, If records, along with supporting documents, that are required to be made under these Regulations are not kept at the upstream oil and gas facility to which they relate, the civic address of the place where they are kept or, if the civic address is not available For a facility that provides information to the Minister for its registration report by way of an approved entity, an indication of any type or subtype of the facility that is used by the entity for the purpose of classifying the facility. The definitions completion, design bleed rate, flowback, gas-to-oil ratio, hydraulic fracturing, pneumatic controller and pneumatic pump in subsection 2(1) of the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector)1 are repealed. SOR/2018-66 The definition fugitive in subsection 2(1) of the Regulations is repealed. The portion of the definition venting in subsection 2(1) of the English version of the Regulations before paragraph (a) is replaced by the following: venting means the emission of hydrocarbon gas from an upstream oil and gas facility in a controlled manner, other than the emission of gas arising from combustion, due to Subsection 2(1) of the Regulations is amended by adding the following in alphabetical order: emission monitoring system means a system consisting of one or more sensors and other equipment that is designed to monitor hydrocarbon gas emissions at an upstream oil and gas facility. (système de mesure et d’enregistrement des émissions) engineer means a person who is registered or licensed to engage in the practice of engineering under the laws of the province in which they practise. (ingénieur) facility emission intensity, in respect of an upstream oil and gas facility, means the ratio, expressed in percent, that is calculated by dividing the total volume of hydrocarbon gas emissions from the facility in the 365-day period preceding the day on which the calculation is made by the greatest of the following volumes: the volume of hydrocarbon gas produced at the facility during that period, the volume of hydrocarbon gas processed at the facility during that period, and the volume of hydrocarbon gas that is equal to the volume of hydrocarbon gas transported from the facility during that period minus the sum of the volumes of hydrocarbon gas referred to in paragraphs (a) and (b). (intensité d’émission) facility emission rate means in respect of an inactive facility, a rate of 0 kg/h; and in respect of any other upstream oil and gas facility, the total volume of hydrocarbon gas emissions from the facility, expressed in kg/h, referred to in the definition facility emission intensity. (seuil du taux d’émission) facility emission reference standard means in respect of an inactive facility, 0%; and in respect of any other upstream oil and gas facility, one of the following values: 0.2%, if, during the 365-day period referred to in the definition facility emission intensity, the volume of hydrocarbon gas produced at the facility is greater than the volume of hydrocarbon gas processed at the facility and the volume of hydrocarbon gas transported from, but not produced or processed at, the facility, respectively, 0.05%, if, during the 365-day period referred to in the definition facility emission intensity, the volume of hydrocarbon gas processed at the facility is greater than the volume of hydrocarbon gas produced at the facility and the volume of hydrocarbon gas transported from, but not produced or processed at, the facility, respectively, 0.11%, if, during the 365-day period referred to in the definition facility emission intensity, the volume of hydrocarbon gas transported from, but not produced or processed at, the facility is greater than the volume of hydrocarbon gas produced at the facility and the volume of hydrocarbon gas processed at the facility, respectively. (étalon de référence) fugitive emission means an unintentional emission of hydrocarbon gas from an upstream oil and gas facility. (émission fugitive) inactive facility means a Type 1 facility or Type 2 facility at which hydrocarbon is not produced, processed or transported and at which those activities have not occurred in respect of hydrocarbon in the previous 365 days. (installation inactive) Type 1 facility means an upstream oil and gas facility at which any of the following equipment is installed: a natural gas compressor; a storage tank for hydrocarbon liquid that is produced at the facility; or a permanent flare. (installation de type 1) Type 2 facility means an upstream oil and gas facility other than a Type 1 facility. (installation de type 2) The Regulations are amended by adding the following after section 2.1: Exclusion from Part 1 Part 1 does not apply to an upstream oil and gas facility to which Part 2 applies. Application of Part 2 If the operator of an upstream oil and gas facility provides the Minister with notice of the use of an emission monitoring system at the facility in accordance with section 2.3, Part 2 applies in respect of that facility beginning on the day specified in the notice. Part 2 ceases to apply If the operator of an upstream oil and gas facility provides the Minister with notice of the discontinuance of use of the emission monitoring system at the facility in accordance with section 2.4, Part 2 ceases to apply to that facility beginning on the day specified in the notice. Notice of use — condition The notice referred to in subsection 2.2(2) must not be provided in respect of an upstream oil and gas facility unless its facility emission intensity, as calculated by an engineer, is less than its facility emission reference standard. However, if the facility has been in operation for less than 365 days, the notice may be provided if an engineer estimates that, after the facility has been in operation for 365 days, its facility emission intensity will be less than its facility emission reference standard. Notice of use — content The notice must be in writing, specify the day on which use of the emission monitoring system is to begin at the facility and contain the following information and documents: the name of the facility and its civic address or, if the civic address is not available, its latitude and longitude to the third decimal place, its location expressed to the nearest unit of the National Topographic System produced by the Department of Natural Resources, or if the facility is located in Manitoba, Saskatchewan or Alberta, the legal subdivision within which it is located; its facility emission intensity and the date of its calculation; its facility emission rate and the date of its determination; the volumes of hydrocarbon gas produced at, processed at and transported from the facility, respectively, during the period used to calculate the facility emission intensity referred in paragraph (b); a description of the sensors and other equipment that constitute the emission monitoring system, including their specifications and datasheets; an attestation, signed and dated by an engineer, indicating that the emission monitoring system meets the requirements set out in section 53; and the name, address and contact information of the engineer who signed the attestation. Despite paragraphs (3)(b) to (d), if the facility has been in operation for less than 365 days, the notice must contain estimates — prepared by an engineer — of the information referred to in those paragraphs. Notice of use — advance notice The notice must be provided to the Minister at least 60 days before the day specified in the notice, unless it is provided before March 1, 2028. Notice of discontinuance of use The notice referred to in subsection 2.2(3) must be in writing, specify the day on which use of the emission monitoring system is to be discontinued at the upstream oil and gas facility and be provided to the Minister at least 60 days before the specified day. The heading “Hydrocarbon Gas Conservation and Destruction Equipment” before section 5 of the Regulations is replaced by the following: The Regulations are amended by adding the following after section 8: Comprehensive inspection Subject to subsections (2) and (3) and section 8.14, a comprehensive inspection for fugitive emissions at an upstream oil and gas facility must be conducted in the case of a Type 1 facility, once in each quarter of the calendar year, at least 60 days after the date of the most recent comprehensive inspection; and in the case of a Type 2 facility, once per calendar year, at least 270 days after the date of the most recent comprehensive inspection. Excluded facilities Subsection (1) does not apply in respect of an inactive facility; and an upstream oil and gas facility that begins operations before January 1, 2028, at which crude oil is produced and at which during the previous calendar year the volume of crude oil produced did not exceed 600 m3, and the combined volume of hydrocarbon gas produced and received did not exceed 12 000 m3. Exception — low temperature A comprehensive inspection is not required to be conducted at a Type 1 facility in a quarter of the calendar year if, on the day before the scheduled day of the inspection in that quarter, the temperature at the facility’s location is forecast to be below -20°C on that scheduled day. Methodology A comprehensive inspection must be conducted using an optical gas-imaging instrument that meets the requirements of subsection (5) or any other instrument that meets the requirements of subsection (6). Optical gas-imaging instrument If a comprehensive inspection is conducted using an optical gas-imaging instrument, the instrument must be capable of imaging gas that is in the spectral range for the compound of highest concentration in the hydrocarbon gas to be measured, and composed of half methane and half propane at a total concentration of 500 ppmv or at a flow rate of 60 g/h when it is leaking from an orifice that is 0.635 cm in diameter; and be operated and maintained in accordance with the manufacturer’s recommendations or, if they are not available, industry standards and best practices. Other instrument If a comprehensive inspection is conducted using an instrument other than an optical gas-imaging instrument, the instrument must be capable of measuring 500 ppmv of hydrocarbon; have a scale that is readable to ±12.5 ppmv of hydrocarbon; and Screening inspection Subject to subsection (2) and section 8.14, a screening inspection for fugitive emissions at an upstream oil and gas facility must be conducted once in each month in which the operator or a representative of the operator visits the facility. Exceptions A screening inspection is not required to be conducted in any of the following months: a month in which a comprehensive inspection is conducted at the facility; a month in which, on the day before the scheduled day of the screening inspection, the temperature at the facility’s location is forecast to be below -20°C on that scheduled day. A screening inspection must be conducted using a monitoring instrument that, when operated in accordance with the manufacturer’s recommendations, is capable of detecting a fugitive emission with a flow rate of 10 kg/h or more. Annual inspection Subject to subsection (3) and section 8.14, an annual inspection for fugitive emissions at an upstream oil and gas facility must be conducted by an auditor who is independent of the operator and owner of the facility that is to be inspected; and has knowledge of and experience with emission detection instruments. Interval The annual inspection must be conducted in each calendar year at least 180 days after the date of the most recent annual inspection and at least 30 days after the date of the most recent comprehensive inspection. An annual inspection is not required to be conducted in any calendar year in which an annual inspection is conducted at the upstream oil and gas facility under subsection 53.1(1). An annual inspection must be conducted using a method that, under standard conditions, provides a 90% or greater probability of detecting a fugitive emission that has a flow rate of 10 kg/h or more. Conduct of inspections An inspection required under any of sections 8.1 to 8.12 must be conducted by a person who, not more than five years before the day on which the inspection occurs, has received training in the calibration, maintenance and operation of the instruments that are used to conduct the inspection; and using instruments that are calibrated, maintained and operated in accordance with the manufacturer’s recommendations, if any. Exclusion — health or safety An inspection required under any of sections 8.1 to 8.12 is not required to include the inspection of an equipment component if that inspection would pose a serious risk to human health or safety. When a fugitive emission is detected at an upstream oil and gas facility, whether as a result of an inspection or otherwise, the equipment component that is emitting the hydrocarbon gas must be repaired if the repair can be carried out while the equipment component is operating, within the applicable period referred to in subsection (2) or (3); and in any other case, before the end of the next planned shutdown of the facility. Repair — flow rate not determined If the equipment component can be repaired while it is operating and the flow rate of the fugitive emission is not determined, the component must be repaired within 24 hours after the emission is detected. Repair — flow rate determined If the equipment component can be repaired while it is operating and the flow rate of the fugitive emission is determined, the component must be repaired in the case of a flow rate that is less than 1 kg/h, within 90 days after the day on which the emission is detected; in the case of a flow rate that is 1 kg/h or more but less than 10 kg/h, within 30 days after the day on which the emission is detected; in the case of a flow rate that is 10 kg/h or more but less than 100 kg/h, within seven days after the day on which the emission is detected; and in the case of a flow rate that is 100 kg/h or more, within 24 hours after the emission is detected. Flow rate reduced However, if a measure is taken that reduces the flow rate of the fugitive emission to less than 10 kg/h during the applicable repair period referred to in paragraph (3)(c) or (d), the repair must be completed within 30 days after the day on which the emission is detected. Volume of hydrocarbon gas In subsections (6) and (7), a reference to a volume of hydrocarbon gas is a reference to that volume expressed in standard m3. Deferral of repair — low level emissions Despite paragraphs (3)(a) and (b) and subsection (4), if the equipment component is emitting hydrocarbon gas at a flow rate of less than 10 kg/h, the repair of the equipment component may be deferred until the day on which the estimated total volume of fugitive emissions that, beginning on the day on which the fugitive emission is detected, would be emitted from that equipment component and from all other equipment components as of that day is equal to the volume of hydrocarbon gas that, if none of those equipment components were repaired, would be emitted during a temporary depressurization of the equipment or a pipeline conducted in order to carry out the repair. Repair — facility shutdown necessary If the equipment component cannot be repaired while it is operating, the next planned shutdown of the upstream oil and gas facility must be scheduled no later than the day on which the estimated total volume of fugitive emissions that, beginning on the day on which the fugitive emission is detected, would be emitted from that equipment component and from all other equipment components as of that day is equal to the volume of hydrocarbon gas that, if none of those equipment components were repaired, would be emitted during a temporary depressurization of the equipment or a pipeline conducted in order to carry out the repair. Verification of repair An equipment component is considered to be repaired when the fugitive emission is no longer detectable using a method that is capable of detecting hydrocarbon gas at a flow rate of 60 g/h or less or at a concentration of 500 ppmv or less. Application — repair while in operation The operator of an upstream oil and gas facility may apply to the Minister to extend the repair period referred to in paragraph 8.15(3)(a) or (b) or subsection 8.15(4) or, in the case where the repair has been deferred in accordance with subsection 8.15(6), to extend the period to complete the repair, if they make the application at least 15 days before the day on which the repair period ends or the day to which the repair has been deferred, as the case may be; and the equipment component is emitting hydrocarbon gas at a flow rate of less than 10 kg/h. Application — deferral of shutdown The operator of an upstream oil and gas facility may apply to the Minister to defer the scheduled day of the next planned shutdown of the facility determined in accordance with subsection 8.15(7) if they make the application at least 15 days before that scheduled day. Content An application made under subsection (1) or (2) must contain the information referred to in Schedule 1 and the following information and documents: in the case of an application made under subsection (1), documents that establish that, as of the making of the application, there are reasonable grounds to conclude that it is not technically feasible for the operator to complete the repair of the equipment component before the end of the applicable repair period or the day to which the repair has been deferred, as the case may be; in the case of an application made under subsection (2), documents that establish that, as of the making of the application, there are reasonable grounds to conclude that it is not technically feasible for the operator to complete the repair of the equipment component before the end of the next planned shutdown of the upstream oil and gas facility; documents that establish that the operator has a plan to repair the equipment component that sets out the measures to be taken to ensure completion of the repair on or before that date, a justification, with supporting documents, for the belief as to why that date is the earliest feasible date to complete the repair, and the measures to be taken to minimize, if not eliminate, any harmful effect on the environment or human health and safety from the emission of hydrocarbon gas before the completion of the repair; and a statement that the implementation of the plan is to begin within 30 days after the day on which the extension or deferral is granted. Conditions If the application contains the information and documents referred to in subsection (3), the Minister must in the case of an application referred to in subsection (1), extend the repair period or the period of time to complete the repair, as the case may be, for a period of no more than six months; and in the case of an application referred to in subsection (2), defer the scheduled day of the next planned shutdown for a period of no more than six months. The Minister must renew an extension or deferral granted under subsection (4) if the operator provides the Minister with a renewal application that contains the information referred to in Schedule 1 and the following information and documents: the information referred to in paragraphs (3)(c) and (d), in the case of an application to renew an extension granted under paragraph (4)(a), documents that establish that, as of the making of the application, there are reasonable grounds to conclude that it is not technically feasible for the operator to complete the repair of the equipment component before the day on which the extended repair period ends or the additional time to complete the repair ends, as the case may be, and in the case of an application to renew a deferral granted under paragraph (4)(b), documents that establish that, as of the making of the application, there are reasonable grounds to conclude that it is not technically feasible for the operator to complete the repair of the equipment component before the day to which the next planned shutdown of the upstream oil and gas facility was deferred; the application is provided in the case of an application to renew an extension referred to in paragraph (4)(a), no later than 45 days before the day on which the extended repair period ends or the additional time to complete the repair ends, as the case may be, and in the case of an application to renew a deferral referred to in paragraph (4)(b), no later than 45 days before the day to which the planned shutdown of the upstream oil and gas facility was deferred; and the extension or deferral, as the case may be, has not been previously renewed. Refusal The Minister must refuse to grant an application referred to in this section if the Minister has reasonable grounds to believe that the operator has provided false or misleading information in the application. Revocation The Minister must revoke an extension or deferral granted under subsection 8.16(4) or renewed under subsection 8.16(5) if the Minister has reasonable grounds to believe that the operator has provided false or misleading information in their application. Limits However, the Minister must not revoke the extension or deferral unless the Minister has provided the operator with Record — inspections and fugitive emissions A record must be made that sets out the following information respecting the inspections and fugitive emissions at an upstream oil and gas facility: for each inspection, its date and time, whether it was a comprehensive inspection, a screening inspection or an annual inspection, the methodology used, the make and model number of each instrument used, information respecting the calibration of each instrument used, and whether a fugitive emission was detected; the name and contact information of the auditor who conducted the annual inspection, along with the name and business address of their employer; for each person who conducted a comprehensive or screening inspection, their name and contact information and the name and business address of their employer, if their employer is not the operator, the dates on which they received training and, for each of those dates, the number of hours of training, and a description of the training received; if, in accordance with paragraph 8.1(2)(b), a comprehensive inspection was not carried out at the facility the volume, expressed in m3, of crude oil produced at the facility in the previous calendar year, and the combined volume, expressed in m3, of hydrocarbon gas produced and received at the facility in the previous calendar year; if, in accordance with subsection 8.1(3) or paragraph 8.11(2)(b), a comprehensive inspection or screening inspection was not carried out at the facility, the temperature that, on the day before the scheduled day of the inspection, was forecasted for the facility’s location on that scheduled day; and for each fugitive emission detected, the unique identifier, if any, assigned to the emission by the operator, a description of the equipment component that emitted the hydrocarbon gas and the location of that equipment component, the date on which the emission was detected, the date on which the emission ended, the flow rate, expressed in kg/h, of the emission before repair of the equipment component, if determined, if the equipment component cannot be repaired while it is operating, the day of the next planned shutdown of the facility and the calculations that support scheduling the shutdown on that day, if a measure referred to in subsection 8.15(4) is taken to reduce the flow rate of the emission to less than 10 kg/h, the flow rate of the emission, expressed in kg/h, after that measure was taken, if the repair of the equipment component was deferred in accordance with subsection 8.15(6), the calculations that were used to identify the date until which the repair can be deferred, and for each equipment component that is repaired, the method that was used to verify the repair. Sections 9 to 19 and the headings before section 20 of the Regulations are repealed. The portion of subsection 20(1) of the Regulations before paragraph (a) is replaced by the following: Application of sections 26, 27 and 37 to 45 Sections 26, 27 and 37 to 45 apply in respect of an upstream oil and gas facility as of the first day of the month that begins after the facility produces or receives, or is expected to produce or receive, a combined volume of more than 60 000 standard m3 of hydrocarbon gas for a period of 12 months, determined as follows: Section 20 of the Regulations is repealed. The portion of section 21 of the Regulations before paragraph (a) is replaced by the following: If, for a given month, none of sections 26, 27 and 37 to 45 apply in respect of an upstream oil and gas facility, a record, with supporting documents, must be made that indicates Section 21 of the Regulations is repealed. Sections 22 to 27 of the Regulations are repealed. The headings before section 28 and sections 28 to 36 of the Regulations are repealed. The heading before section 37 and sections 37 to 45 of the Regulations are repealed. The Regulations are amended by adding the following after section 45: Application of sections 46 to 50 Sections 46 to 50 apply in respect of an upstream oil and gas facility if operations at the facility begin before January 1, 2028, as of January 1, 2030; and if operations at the facility begin on or after January 1, 2028, as of the day on which it begins operations. Section 45.1 of the Regulations and the heading “Application” before it are repealed. The Regulations are amended by adding the following after section 45.1: Engineering study required The destruction of hydrocarbon gas at an upstream oil and gas facility, other than destruction that is necessary to avoid serious risk to human health or safety arising from an emergency situation, must be supported by an engineering study that concludes that use of the hydrocarbon gas to produce useful heat or energy is not feasible in the circumstances. Reassessment The engineering study must be reassessed every 12 months by an engineer and if the conclusion referred to in subsection (1) can no longer be supported, the destruction of hydrocarbon gas at the facility must cease. Hydrocarbon gas destruction equipment, other than a catalytic oxidation system, that is used at an upstream oil and gas facility must have a combustion system that, when hydrocarbon gas is routed to that system, maintains the stable combustion of hydrocarbon gas without generating any visible emission, and has a carbon conversion efficiency of at least 98%; and Visual inspection If the combustion system referred to in paragraph (1)(a) does not have an automatic flame failure detection system, the hydrocarbon gas destruction equipment must be visually inspected at least once every seven days to ensure that stable combustion of hydrocarbon gas is being maintained. Catalytic oxidation system A catalytic oxidation system that is used at an upstream oil and gas facility for the purpose of hydrocarbon gas destruction must be operated such that hydrocarbon gas is not routed to the system when the catalyst temperature is below that recommended by the equipment manufacturer; and be operated and maintained in accordance with the manufacturer’s recommendations. If destruction of hydrocarbon gas occurs at an upstream oil and gas facility, a record must be made that contains a copy of the engineering study referred to in subsection 46(1); and as applicable, a copy of the conclusions of any reassessment of that study performed in accordance with subsection 46(2). The following records must be made respecting the hydrocarbon gas destruction equipment that is located at the facility: a record that indicates whether the equipment consists of a combustion system or catalytic oxidation system; in the case where the equipment consists of a combustion system, a record that indicates whether it has an automatic flame failure detection system and how the flame will be relit if it fails, and if the combustion system does not have an automatic flame failure detection system, a record of each visual inspection performed in accordance with subsection 47(2); and a record that indicates how the equipment meets the requirements of subsection 47(1) or (3), as applicable, and that contains a description of how the equipment is operated and maintained, including the manufacturer’s recommendations — or, if they are not available — a list of the industry standards and best practices for its operation and maintenance. Venting prohibited Subject to subsection (2), hydrocarbon gas must not be vented from an upstream oil and gas facility. Hydrocarbon gas may be vented from the facility if it is vented as part of planned equipment maintenance or a planned temporary depressurization of equipment or a pipeline and measures are taken to minimize the volume of hydrocarbon gas that is vented; it is necessary to avoid serious risk to human health or safety arising from an emergency situation;

the heating value of the hydrocarbon gas or its flow rate are insufficient to sustain continuous destruction of the gas by hydrocarbon gas destruction equipment; the use of hydrocarbon gas destruction equipment or hydrocarbon gas conservation equipment would prolong an interruption of the hydrocarbon gas supply to the public; or crude oil is produced at the facility and operations at the facility began before January 1, 2028, in the calendar year before the one in which the venting is to occur, the volume of crude oil produced at the facility did not exceed 600 m3 and the total volume of hydrocarbon gas vented from the facility did not exceed 12 000 m3, the venting is not from a pneumatic device that uses pressurized gas to generate mechanical energy, and measures are taken to minimize the volume of hydrocarbon gas that is vented, such as the conservation or destruction of the gas. Venting limit Despite subsection (2), no more than 12 000 m3 of hydrocarbon gas may be vented in a calendar year from an upstream oil and gas facility referred to in paragraph (2)(e). Record — venting A record must be made that sets out the following information respecting the venting of hydrocarbon gas from an upstream oil and gas facility: for each instance of venting referred to in paragraphs 49(2)(a) to (d), the date, time and duration of the venting, identification of the equipment component that is the source of the venting, the flow rate of the vented hydrocarbon gas, expressed in kg/h, under standard conditions, a description of the circumstances leading up to the venting and the reasons for it, including identification of the exception referred to in subsection 49(2) that is to be relied on and an explanation of why it is applicable in the circumstances, and the measures that were taken to minimize the volume of the vented hydrocarbon gas; and in respect of venting referred to in paragraph 49(2)(e), the volume of crude oil, expressed in m3, that was produced at the facility in the previous calendar year, the volume of hydrocarbon gas, expressed in m3, that was vented from facility in the previous calendar year, and the measures that were taken to minimize the volume of vented hydrocarbon gas. After providing notice After providing the notice referred to in subsection 2.2(2), the operator must ensure that the facility emission intensity for the upstream oil and gas facility, as calculated by an engineer, remains less than its facility emission reference standard. Updates The facility emission intensity and facility emission rate for the facility must be updated annually and after each analysis that is conducted under subsection 53.2(2); and any physical change to the facility or change to its operation that would affect, by 10% or more, the volume of the facility’s hydrocarbon gas emissions or the volume of hydrocarbon gas that is produced or processed at the facility or transported from it. Adjustment to facility emission rate A facility emission rate that is updated, including in accordance with subsection (2), must be adjusted to include any change in the volume of hydrocarbon gas emissions from the facility, expressed in kg/h, that an engineer estimates will occur in the 365-day period following a physical change to the facility or a change to its operation that has occurred since the day on which the rate was last determined. A record must be made that sets out the following information: the facility emission intensity and facility emission rate for the upstream oil and gas facility on the day specified in the notice provided under subsection 2.2(2); and each update to its facility emission intensity and facility emission rate, the date of the update and the reason for it. Continuous operation An emission monitoring system must be operating at all times, except for any period during which all or part of the system is undergoing preventive maintenance. Preventive maintenance The preventive maintenance must not be performed during any period in which an emission of hydrocarbon gas is planned or expected to occur at the upstream oil and gas facility. Sensors and other equipment An emission monitoring system must meet the following requirements: its sensors and other equipment must be capable, under controlled laboratory conditions, of detecting hydrocarbon gas emissions that have a total flow rate of 1 kg/h or more, and be placed at locations where they can detect hydrocarbon gas emissions at the facility; its sensors must take readings in the case of a Type 1 facility, at least once every 15 minutes, and in the case of a Type 2 facility or an inactive facility, at least once every 12 hours; it must record each reading taken under paragraph (b); and it must generate an alert when the total flow rate of hydrocarbon gas emissions detected at the facility exceeds the facility emission rate by 1 kg/h or more. Calibration All sensors and other equipment that constitute the emission monitoring system must be calibrated in accordance with the manufacturer’s recommendations such that their measurements have a maximum margin of error of ±20%. Subject to subsections (2) and (3), an annual inspection for hydrocarbon gas emissions at an upstream oil and gas facility must be conducted once per calendar year, with no less than 180 days having elapsed since the date of the last annual inspection, by an auditor who An annual inspection is not required to be conducted at the upstream oil and gas facility in any calendar year in which an annual inspection is conducted at the facility under subsection 8.12(1). An annual inspection is not required to include the inspection of an equipment component if that inspection would pose a serious risk to human health or safety. An annual inspection must be conducted using methods that, under standard conditions, provide a 90% or greater probability of detecting hydrocarbon gas emissions at the facility that have a total flow rate of 10 kg/h or more. Record — annual inspection A record must be made that sets out the following information respecting each annual inspection: its date and time; the name and contact information of the auditor who conducted the inspection, along with the name and business address of their employer; a description of the methodology and equipment used; information respecting the calibration of each instrument used; whether hydrocarbon gas emissions were detected; and if hydrocarbon gas emissions were detected, their total flow rate, expressed in kg/h, the unique identifier, if any, assigned to those emissions by the operator, and a list of the measures that were taken to reduce those emissions, if any. Period for emission reduction If the total flow rate of hydrocarbon gas emissions detected at an upstream oil and gas facility is higher than its facility emission rate by 1 kg/h or more, the total flow rate must be reduced to less than 1 kg/h above the facility emission rate as soon as feasible, but in any case, by no later than if the total flow rate is higher than the facility emission rate by 1 kg/h or more, but less than 10 kg/h higher than that rate, 30 days after the day on which the emissions are detected; if the total flow rate is higher than the facility emission rate by 10 kg/h or more but less than 100 kg/h higher than that rate, seven days after the day on which the emissions are detected; and if the total flow rate is higher than the facility emission rate by 100 kg/h or more, 24 hours after the emissions are detected. Analysis required An analysis must be conducted in respect of each instance when the total flow rate of the hydrocarbon gas emissions detected at the upstream oil and gas facility is higher than its facility emission rate by 10 kg/h or more. Record — system and emissions the date, time and duration of each instance when the emission monitoring system is not in operation; for each instance when the total flow rate of hydrocarbon gas emissions at the upstream oil and gas facility was higher than its facility emission rate by 1 kg/h or more, the maximum total flow rate of the emissions, expressed in kg/h, if known, the date and time when the emissions were detected, the date and time when the total flow rate of the emissions was reduced to less than 1 kg/h above the facility emission rate, a list of the measures that were taken to reduce the total flow rate of the emissions, and the period, if any, during which the facility was shut down; and the results of each analysis conducted under subsection (2). Provided to the Minister On or before June 30 in each year, an annual report must be provided to the Minister that contains the following information and documents in respect of the upstream oil and gas facility for the preceding calendar year: with respect to the annual inspection of the facility, as applicable, a copy of the record referred to in subsection 53.1(5) or a copy of the information referred to in paragraphs 8.18(a), (b) and (f), and every reading of the total flow rate of hydrocarbon gas emissions at the facility that was taken and recorded by the emission monitoring system during the annual inspection; the information referred to in paragraphs 53.2(3)(b) and (c) respecting the total flow rate of hydrocarbon gas emissions during the calendar year at the facility; each update to its facility emission intensity and facility emission rate, the calculations that support the update, the date of the update and the reason for it; and the last facility emission intensity and facility emission rate calculated in the calendar year preceding the calendar year for which the report is provided. Subsections 54(1) and (2) of the Regulations are replaced by the following: An upstream oil and gas facility must be registered by providing a registration report for the facility to the Minister that contains the information referred to in Schedule 3. The facility must be registered not later than 120 days after the later of January 1, 2028 and the day on which operations at the facility begin. The Regulations are amended by adding the following after section 55: Information required If an upstream oil and gas facility is registered in accordance with subsection 54(1) before January 1, 2028, a supplementary notice that contains the information referred to in item 7 of Schedule 3 must be provided to the Minister by no later than April 30, 2028. Deeming The information provided to the Minister under subsection (1) is deemed to be information provided in the facility’s registration report. Schedule 1 to the Regulations is amended by replacing the references after the heading “SCHEDULE 1” with the following: Schedule 1 to the Regulations is amended by adding the following after item 4: The date on which the fugitive emission was detected. The flow rate of the fugitive emission, expressed in kg/h. If repair of the equipment component was deferred in accordance with subsection 8.15(6), the day to which the repair was deferred and the calculations that supported deferral to that day. If repair of the equipment component requires the shutdown of the upstream oil and gas facility, the day of the next shutdown scheduled in accordance with subsection 8.15(7) and the calculations that support scheduling it on that day. Schedule 2 to the Regulations is repealed. Schedule 3 to the Regulations is amended by replacing the references after the heading “SCHEDULE 3” with the following: Schedule 3 to the Regulations is amended by adding the following after item 6: Identification of the facility as either a Type 1 facility, a Type 2 facility or an inactive facility.