Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (SOR/2018-66)
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Regulations are current to 2026-03-17 and last amended on 2025-12-12. Previous Versions
AMENDMENTS NOT IN FORCE
— SOR/2025-280, ss. 1(1), (2), (4) and (5)
1 (1) 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Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector)Footnote 1 are repealed.
Return to footnote 1SOR/2018-66
(2) The definition fugitive in subsection 2(1) of the Regulations is repealed.
(4) 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
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
(5) Subsection 2(1) of the Regulations is amended by adding the following in alphabetical order:
- emission monitoring system
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
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
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:
(a) the volume of hydrocarbon gas produced at the facility during that period,
(b) the volume of hydrocarbon gas processed at the facility during that period, and
(c) 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
facility emission rate means
(a) in respect of an inactive facility, a rate of 0 kg/h; and
(b) 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
facility emission reference standard means
(a) in respect of an inactive facility, 0%; and
(b) in respect of any other upstream oil and gas facility, one of the following values:
(i) 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,
(ii) 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,
(iii) 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
fugitive emission means an unintentional emission of hydrocarbon gas from an upstream oil and gas facility. (émission fugitive)
- inactive facility
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
Type 1 facility means an upstream oil and gas facility at which any of the following equipment is installed:
(a) a natural gas compressor;
(b) a storage tank for hydrocarbon liquid that is produced at the facility; or
(c) a permanent flare. (installation de type 1)
- Type 2 facility
Type 2 facility means an upstream oil and gas facility other than a Type 1 facility. (installation de type 2)
— SOR/2025-280, s. 3
3 The Regulations are amended by adding the following after section 2.1:
Exclusion from Part 1
2.2 (1) Part 1 does not apply to an upstream oil and gas facility to which Part 2 applies.
Application of Part 2
(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
(3) 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
2.3 (1) 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.
Exception
(2) 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
(3) 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:
(a) the name of the facility and its civic address or, if the civic address is not available,
(i) its latitude and longitude to the third decimal place,
(ii) its location expressed to the nearest unit of the National Topographic System produced by the Department of Natural Resources, or
(iii) if the facility is located in Manitoba, Saskatchewan or Alberta, the legal subdivision within which it is located;
(b) its facility emission intensity and the date of its calculation;
(c) its facility emission rate and the date of its determination;
(d) 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);
(e) a description of the sensors and other equipment that constitute the emission monitoring system, including their specifications and datasheets;
(f) an attestation, signed and dated by an engineer, indicating that the emission monitoring system meets the requirements set out in section 53; and
(g) the name, address and contact information of the engineer who signed the attestation.
Exception
(4) 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
(5) 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
2.4 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.
— SOR/2025-280, s. 5
5 The heading “Hydrocarbon Gas Conservation and Destruction Equipment” before section 5 of the Regulations is replaced by the following:
Hydrocarbon Gas Conservation Equipment
— SOR/2025-280, s. 6
6 The Regulations are amended by adding the following after section 8:
Detection of Fugitive Emissions and Repair Program
Comprehensive inspection
8.1 (1) 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
(a) 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
(b) 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
(2) Subsection (1) does not apply in respect of
(a) an inactive facility; and
(b) 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
(i) the volume of crude oil produced did not exceed 600 m3, and
(ii) the combined volume of hydrocarbon gas produced and received did not exceed 12 000 m3.
Exception — low temperature
(3) 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
(4) 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
(5) If a comprehensive inspection is conducted using an optical gas-imaging instrument, the instrument must
(a) be capable of imaging gas that is
(i) in the spectral range for the compound of highest concentration in the hydrocarbon gas to be measured, and
(ii) 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
(b) be operated and maintained in accordance with the manufacturer’s recommendations or, if they are not available, industry standards and best practices.
Other instrument
(6) If a comprehensive inspection is conducted using an instrument other than an optical gas-imaging instrument, the instrument must
(a) be capable of measuring 500 ppmv of hydrocarbon;
(b) have a scale that is readable to ±12.5 ppmv of hydrocarbon; and
(c) be operated and maintained in accordance with the manufacturer’s recommendations or, if they are not available, industry standards and best practices.
Screening inspection
8.11 (1) 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
(2) A screening inspection is not required to be conducted in any of the following months:
(a) a month in which a comprehensive inspection is conducted at the facility;
(b) 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.
Methodology
(3) 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
8.12 (1) 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
(a) is independent of the operator and owner of the facility that is to be inspected; and
(b) has knowledge of and experience with emission detection instruments.
Interval
(2) 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.
Exception
(3) 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).
Methodology
(4) 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
8.13 An inspection required under any of sections 8.1 to 8.12 must be conducted
(a) 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
(b) using instruments that are calibrated, maintained and operated in accordance with the manufacturer’s recommendations, if any.
Exclusion — health or safety
8.14 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.
Period for repair
8.15 (1) 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
(a) 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
(b) in any other case, before the end of the next planned shutdown of the facility.
Repair — flow rate not determined
(2) 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
(3) 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
(a) 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;
(b) 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;
(c) 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
(d) 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
(4) 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
(5) 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
(6) 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
(7) 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
(8) 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
8.16 (1) 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
(a) 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
(b) the equipment component is emitting hydrocarbon gas at a flow rate of less than 10 kg/h.
Application — deferral of shutdown
(2) 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
(3) An application made under subsection (1) or (2) must contain the information referred to in Schedule 1 and the following information and documents:
(a) 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;
(b) 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;
(c) documents that establish that the operator has a plan to repair the equipment component that sets out
(i) the expected date for the completion of the repair,
(ii) the measures to be taken to ensure completion of the repair on or before that date,
(iii) a justification, with supporting documents, for the belief as to why that date is the earliest feasible date to complete the repair, and
(iv) 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
(d) 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
(4) If the application contains the information and documents referred to in subsection (3), the Minister must
(a) 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
(b) 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.
Renewal
(5) The Minister must renew an extension or deferral granted under subsection (4) if
(a) the operator provides the Minister with a renewal application that contains the information referred to in Schedule 1 and the following information and documents:
(i) the information referred to in paragraphs (3)(c) and (d),
(ii) 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
(iii) 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;
(b) the application is provided
(i) 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
(ii) 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
(c) the extension or deferral, as the case may be, has not been previously renewed.
Refusal
(6) 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
8.17 (1) 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
(2) However, the Minister must not revoke the extension or deferral unless the Minister has provided the operator with
(a) written reasons for the proposed revocation; and
(b) an opportunity to be heard, by written representation, in respect of the proposed revocation.
Record — inspections and fugitive emissions
8.18 A record must be made that sets out the following information respecting the inspections and fugitive emissions at an upstream oil and gas facility:
(a) for each inspection,
(i) its date and time,
(ii) whether it was a comprehensive inspection, a screening inspection or an annual inspection,
(iii) the methodology used,
(iv) the make and model number of each instrument used,
(v) information respecting the calibration of each instrument used, and
(vi) whether a fugitive emission was detected;
(b) the name and contact information of the auditor who conducted the annual inspection, along with the name and business address of their employer;
(c) for each person who conducted a comprehensive or screening inspection,
(i) their name and contact information and the name and business address of their employer, if their employer is not the operator,
(ii) the dates on which they received training and, for each of those dates, the number of hours of training, and
(iii) a description of the training received;
(d) if, in accordance with paragraph 8.1(2)(b), a comprehensive inspection was not carried out at the facility
(i) the volume, expressed in m3, of crude oil produced at the facility in the previous calendar year, and
(ii) the combined volume, expressed in m3, of hydrocarbon gas produced and received at the facility in the previous calendar year;
(e) 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
(f) for each fugitive emission detected,
(i) the unique identifier, if any, assigned to the emission by the operator,
(ii) a description of the equipment component that emitted the hydrocarbon gas and the location of that equipment component,
(iii) the date on which the emission was detected,
(iv) the date on which the emission ended,
(v) the flow rate, expressed in kg/h, of the emission before repair of the equipment component, if determined,
(vi) 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,
(vii) 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,
(viii) 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
(ix) for each equipment component that is repaired, the method that was used to verify the repair.
— SOR/2025-280, s. 7
7 Sections 9 to 19 and the headings before section 20 of the Regulations are repealed.
— SOR/2025-280, s. 8
8 (1) 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
20 (1) 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:
(2) Section 20 of the Regulations is repealed.
— SOR/2025-280, s. 9
9 (1) The portion of section 21 of the Regulations before paragraph (a) is replaced by the following:
Records — non-application
21 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
(2) Section 21 of the Regulations is repealed.
— SOR/2025-280, s. 10
10 Sections 22 to 27 of the Regulations are repealed.
— SOR/2025-280, s. 11
11 The headings before section 28 and sections 28 to 36 of the Regulations are repealed.
— SOR/2025-280, s. 12
12 The heading before section 37 and sections 37 to 45 of the Regulations are repealed.
— SOR/2025-280, s. 13
13 The Regulations are amended by adding the following after section 45:
Hydrocarbon Gas Destruction and Venting
Application
Application of sections 46 to 50
45.1 Sections 46 to 50 apply in respect of an upstream oil and gas facility
(a) if operations at the facility begin before January 1, 2028, as of January 1, 2030; and
(b) if operations at the facility begin on or after January 1, 2028, as of the day on which it begins operations.
— SOR/2025-280, s. 14
14 Section 45.1 of the Regulations and the heading “Application” before it are repealed.
— SOR/2025-280, s. 16
16 The Regulations are amended by adding the following after section 45.1:
Hydrocarbon Gas Destruction
Engineering study required
46 (1) 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
(2) 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
47 (1) Hydrocarbon gas destruction equipment, other than a catalytic oxidation system, that is used at an upstream oil and gas facility must
(a) have a combustion system that, when hydrocarbon gas is routed to that system,
(i) maintains the stable combustion of hydrocarbon gas without generating any visible emission, and
(ii) has a carbon conversion efficiency of at least 98%; and
(b) be operated and maintained in accordance with the manufacturer’s recommendations or, if they are not available, industry standards and best practices.
Visual inspection
(2) 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
(3) A catalytic oxidation system that is used at an upstream oil and gas facility for the purpose of hydrocarbon gas destruction must
(a) 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
(b) be operated and maintained in accordance with the manufacturer’s recommendations.
Records
48 (1) If destruction of hydrocarbon gas occurs at an upstream oil and gas facility, a record must be made that contains
(a) a copy of the engineering study referred to in subsection 46(1); and
(b) as applicable, a copy of the conclusions of any reassessment of that study performed in accordance with subsection 46(2).
Records
(2) The following records must be made respecting the hydrocarbon gas destruction equipment that is located at the facility:
(a) a record that indicates whether the equipment consists of a combustion system or catalytic oxidation system;
(b) in the case where the equipment consists of a combustion system,
(i) a record that indicates whether it has an automatic flame failure detection system and how the flame will be relit if it fails, and
(ii) 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
(c) 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
Venting prohibited
49 (1) Subject to subsection (2), hydrocarbon gas must not be vented from an upstream oil and gas facility.
Exceptions
(2) Hydrocarbon gas may be vented from the facility if
(a) 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;
(b) it is necessary to avoid serious risk to human health or safety arising from an emergency situation;
(c) 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;
(d) 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
(e) crude oil is produced at the facility and
(i) operations at the facility began before January 1, 2028,
(ii) 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,
(iii) the venting is not from a pneumatic device that uses pressurized gas to generate mechanical energy, and
(iv) measures are taken to minimize the volume of hydrocarbon gas that is vented, such as the conservation or destruction of the gas.
Venting limit
(3) 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
50 A record must be made that sets out the following information respecting the venting of hydrocarbon gas from an upstream oil and gas facility:
(a) for each instance of venting referred to in paragraphs 49(2)(a) to (d),
(i) the date, time and duration of the venting,
(ii) identification of the equipment component that is the source of the venting,
(iii) the flow rate of the vented hydrocarbon gas, expressed in kg/h, under standard conditions,
(iv) 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
(v) the measures that were taken to minimize the volume of the vented hydrocarbon gas; and
(b) in respect of venting referred to in paragraph 49(2)(e),
(i) the volume of crude oil, expressed in m3, that was produced at the facility in the previous calendar year,
(ii) the volume of hydrocarbon gas, expressed in m3, that was vented from facility in the previous calendar year, and
(iii) the measures that were taken to minimize the volume of vented hydrocarbon gas.
PART 2Upstream Oil and Gas Facilities Using an Emission Monitoring System
System Operation
After providing notice
51 (1) 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
(2) The facility emission intensity and facility emission rate for the facility must be updated annually and after
(a) each analysis that is conducted under subsection 53.2(2); and
(b) 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
(3) 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.
Record
(4) A record must be made that sets out the following information:
(a) 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
(b) each update to its facility emission intensity and facility emission rate, the date of the update and the reason for it.
Continuous operation
52 (1) 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
(2) 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.
System Requirements
Sensors and other equipment
53 (1) An emission monitoring system must meet the following requirements:
(a) its sensors and other equipment must
(i) be capable, under controlled laboratory conditions, of detecting hydrocarbon gas emissions that have a total flow rate of 1 kg/h or more, and
(ii) be placed at locations where they can detect hydrocarbon gas emissions at the facility;
(b) its sensors must take readings
(i) in the case of a Type 1 facility, at least once every 15 minutes, and
(ii) in the case of a Type 2 facility or an inactive facility, at least once every 12 hours;
(c) it must record each reading taken under paragraph (b); and
(d) 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
(2) 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%.
Inspection
Annual inspection
53.1 (1) 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
(a) is independent of the operator and owner of the facility that is to be inspected; and
(b) has knowledge of and experience with emission detection instruments.
Exception
(2) 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).
Exception
(3) 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.
Methodology
(4) 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
(5) A record must be made that sets out the following information respecting each annual inspection:
(a) its date and time;
(b) the name and contact information of the auditor who conducted the inspection, along with the name and business address of their employer;
(c) a description of the methodology and equipment used;
(d) information respecting the calibration of each instrument used;
(e) whether hydrocarbon gas emissions were detected; and
(f) if hydrocarbon gas emissions were detected,
(i) their total flow rate, expressed in kg/h,
(ii) the unique identifier, if any, assigned to those emissions by the operator, and
(iii) a list of the measures that were taken to reduce those emissions, if any.
Emissions
Period for emission reduction
53.2 (1) 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
(a) 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;
(b) 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
(c) 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
(2) 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
(3) A record must be made that sets out the following information:
(a) the date, time and duration of each instance when the emission monitoring system is not in operation;
(b) 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,
(i) the maximum total flow rate of the emissions, expressed in kg/h, if known,
(ii) the date and time when the emissions were detected,
(iii) 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,
(iv) a list of the measures that were taken to reduce the total flow rate of the emissions, and
(v) the period, if any, during which the facility was shut down; and
(c) the results of each analysis conducted under subsection (2).
Annual Report
Provided to the Minister
53.3 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:
(a) with respect to the annual inspection of the facility,
(i) 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
(ii) 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;
(b) 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;
(c) 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
(d) the last facility emission intensity and facility emission rate calculated in the calendar year preceding the calendar year for which the report is provided.
— SOR/2025-280, s. 17
17 Subsections 54(1) and (2) of the Regulations are replaced by the following:
Registration report
54 (1) 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.
Date of registration
(2) 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.
— SOR/2025-280, s. 18
18 The Regulations are amended by adding the following after section 55:
Supplementary Notice
Information required
55.1 (1) 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
(2) The information provided to the Minister under subsection (1) is deemed to be information provided in the facility’s registration report.
— SOR/2025-280, s. 19
19 Schedule 1 to the Regulations is amended by replacing the references after the heading “SCHEDULE 1” with the following:
(Subsection 8.16(3) and paragraph 8.16(5)(a))
— SOR/2025-280, s. 20
20 Schedule 1 to the Regulations is amended by adding the following after item 4:
4.1 The date on which the fugitive emission was detected.
4.2 The flow rate of the fugitive emission, expressed in kg/h.
4.3 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.
4.4 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.
— SOR/2025-280, s. 21
21 Schedule 2 to the Regulations is repealed.
— SOR/2025-280, s. 22
22 Schedule 3 to the Regulations is amended by replacing the references after the heading “SCHEDULE 3” with the following:
(Subsections 54(1) and (3) and 55.1(1))
— SOR/2025-280, s. 23
23 Schedule 3 to the Regulations is amended by adding the following after item 6:
7 Identification of the facility as either a Type 1 facility, a Type 2 facility or an inactive facility.
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