Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector): SOR/2020-231

Canada Gazette, Part II, Volume 154, Number 23

Registration
SOR/2020-231 October 26, 2020

CANADIAN ENVIRONMENTAL PROTECTION ACT, 1999

P.C. 2020-824 October 23, 2020

Whereas, pursuant to subsection 332(1)footnote a of the Canadian Environmental Protection Act, 1999footnote b, 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 Volatile Organic Compounds (Petroleum Sector) and the proposed Regulations Amending the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999), 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 6footnote c of that Act;

And whereas the Governor in Council, in accordance with subsection 93(4) of that Act, 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, in the opinion of the Governor in Council, provides 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) and section 286.1footnote d of the Canadian Environmental Protection Act, 1999 footnote b, makes the annexed Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector).

TABLE OF PROVISIONS

Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector)

Interpretation

Application

Leak Detection and Repair Requirements

Requirements for Certain Equipment Components

Fenceline Monitoring Requirements

Reporting Requirements

Coming into Force

SCHEDULE 1

SCHEDULE 2

SCHEDULE 3

Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector)

Interpretation

Definitions

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

authorized official
means
  • (a) in respect of an operator who is an individual, that individual or another individual who is authorized to act on the operator’s behalf;
  • (b) in respect of an operator that is a corporation, an officer of the corporation who is authorized to act on its behalf; and
  • (c) in respect of an operator that is an entity other than a corporation, an individual who is authorized to act on its behalf. (agent autorisé)
certified low-leaking valve
means a valve for which the manufacturer has issued a written warranty, based on the results of testing conducted in accordance with generally accepted engineering practices, that, for a period of five years, no leak of VOCs from the valve will be of a concentration greater than 100 ppmv. (soupape certifiée à faibles fuites)
certified low-leaking valve packing
means valve packing for which the manufacturer has issued a written warranty, based on the results of testing conducted in accordance with generally accepted engineering practices, that, for a period of five years, no leak of VOCs from the valve will be of a concentration greater than 100 ppmv. (garniture certifiée à faibles fuites)
control device
means an enclosed combustion device, a vapour recovery system or any other device used to control the release of VOCs into the environment. (dispositif de contrôle)
drop rate
means the average number of drops per minute observed visually over a period of three minutes. (débit en goutte)
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 Title 40, part 60 of the Code of Federal Regulations of the United States. (méthode 21 de l’EPA)
EPA Method 325A
means the method of the Environmental Protection Agency of the United States entitled Method 325A — Volatile Organic Compounds from Fugitive and Area Sources: Sampler Deployment and VOC Sample Collection, set out in Appendix A to Title 40, part 63 of the Code of Federal Regulations of the United States. (méthode 325A de l’EPA)
EPA Method 325B
means the method of the Environmental Protection Agency of the United States entitled Method 325B — Volatile Organic Compounds from Fugitive and Area Sources: Sampler Preparation and Analysis, set out in Appendix A to Title 40, part 63 of the Code of Federal Regulations of the United States. (méthode 325B de l’EPA)
equipment component
means any piece of process equipment that comes into contact with a fluid containing 10% or more VOCs by weight, as determined in accordance with ASTM International standard E260, Standard Practice for Packed Column Gas Chromatography, or E169, Standard Practices for General Techniques of Ultraviolet-Visible Quantitative Analysis, or with other generally accepted engineering practices. (pièce d’équipement)
facility
means the buildings, other structures and stationary equipment that are located on a single site or on several sites that are operated in an integrated way. (installation)
heavy liquid
means a liquid that has a vapour pressure of less than 1.013 kPa at 20°C. (liquide lourd)
leak detection instrument
means a portable monitoring instrument or an optical gas-imaging instrument. (instrument de détection des fuites)
light liquid
means a liquid that has a vapour pressure equal to or greater than 1.013 kPa at 20°C. (liquide léger)
liquid petroleum product
means
  • (a) naphtha;
  • (b) gasoline;
  • (c) aviation turbine fuel;
  • (d) kerosene;
  • (e) diesel fuel;
  • (f) light fuel oil;
  • (g) heavy fuel oil;
  • (h) naval distillate, bunker fuel or any other marine fuel;
  • (i) gas oil;
  • (j) lubricant basestock or petroleum-based lubricant;
  • (k) asphalt; or
  • (l) synthetic crude oil. (produit pétrolier liquide)
minor assembly
means a type of equipment component that is composed of up to 25 other equipment components that are connected together and that each come into contact with the same type of fluid and have a diameter of less than 1.875 cm. (petit assemblage)
operator,
in respect of a facility, means the person who operates or has the charge, management or control of the facility. (exploitant)
pipe
means any pipe, regardless of whether it is rigid or flexible. (conduite)
ppmv
means parts per million by volume. (ppmv)
repair, in respect of an equipment component,
includes replacement. (réparation)
sampling tube
means a passive diffusive tube that contains a sorbent used for collecting VOCs. (tube d’échantillonnage)
volatile organic compound or VOC
means a compound that participates in atmospheric photochemical reactions and that is not excluded under item 65 of Schedule 1 to the Canadian Environmental Protection Act, 1999. (composé organique volatil ou COV)

Incorporation by reference

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

Application

Facilities subject to the Regulations

2 (1) These Regulations apply in respect of a facility that

Facilities considered adjacent

(2) For greater certainty, facilities that are separated by a railway track or a road are considered to be adjacent facilities.

Leak Detection and Repair Requirements

Leak detection and repair program

3 (1) The operator of a facility must establish and maintain a leak detection and repair program to control the release of volatile organic compounds from equipment components at the facility.

Requirements

(2) For the purpose of subsection (1), the operator must

Equipment components to be listed in inventory

4 (1) Every equipment component, other than the following ones, must be listed in the inventory:

Information for each equipment component

(2) The inventory of equipment components must contain all of the following information in respect of each component that is listed in the inventory:

Before 2027 — difficult to inspect

(3) Before 2027, the inventory of equipment components must, for each equipment component that is a distance of more than two metres above a permanent support surface, include the designation “difficult to inspect”.

Updating inventory

(4) The inventory of equipment components must be updated only once in each calendar year, before the first inspection carried out in that year under subsection 6(1) or (2).

Portable monitoring instruments

5 (1) A portable monitoring instrument must meet all of the following requirements:

Optical gas-imaging instruments

(2) An optical gas-imaging instrument must meet the following requirements:

Detection sensitivity level

(3) For the purpose of paragraphs (2)(a) and (c), the required detection sensitivity level is 60 grams per hour.

Inspection — equipment components

6 (1) Subject to subsections (2) and (3), all equipment components at a facility that are listed in its inventory must be inspected for leaks three times per calendar year. Each inspection of an equipment component must be carried out in one of the following manners at least one month, but not more than six months, after the most recent inspection of that equipment component under this subsection:

Before 2027 — difficult to inspect

(2) Subject to subsection (3), before 2027, all equipment components at a facility that are designated in its inventory under subsection 4(3) as “difficult to inspect” must be inspected for leaks once per calendar year. Each inspection of an equipment component must be carried out in one of the following manners, at least three months after the most recent inspection of that equipment component under this subsection:

Exception

(3) The following components are exempt from the inspections required by subsections (1) and (2):

Pumps — sensor check

(4) The sensor referred to in subparagraph (3)(a)(iii) must be checked daily to determine whether there has been a failure of the barrier fluid system, unless the sensor is equipped with an audible alarm for the purpose of indicating such a failure or a mechanism that shuts down the pump in the event of such a failure.

Pumps — visual inspection

(5) Pumps that are listed in the inventory must also be inspected visually for leaks once per week.

Required training

7 (1) The inspections referred to in paragraphs 6(1)(b) and (2)(b), subsection 8(4) and paragraph 8(10)(b) must be carried out by an individual who, not more than 12 months before the first time that they carry out an inspection, has received training in operating, maintaining and calibrating leak detection instruments, in accordance with section 5, and carrying out inspections for leaks using those instruments.

Record of training

(2) The operator must keep a record of the training completed by the individual carrying out the inspections that contains

Retention period

(3) The operator must retain the record, as well as any supporting documents, at the facility for at least five years.

Repairs

8 (1) An equipment component that has a significant leak must be repaired not later than 15 days after the day on which the leak is detected, unless it has been flagged for repair under subsection (6). However, before flagging an equipment component for repair under that subsection, the operator must attempt to repair the component within 15 days using generally accepted best repair practices for the component.

Presumed significant leak

(2) A leak in an equipment component that is detected by using a leak detection instrument or by using sensory methods, including auditory, visual or olfactory methods, or that is detected as a result of an indication from a sensor that the component’s barrier fluid system has failed, is considered to be a significant leak unless

Inspection before repair — heavy-liquid equipment component

(3) If a leak in a heavy-liquid equipment component is detected by a means other than a visual inspection, the equipment component must, before it is repaired, be inspected visually for leaks.

Inspection before repair — gas or light-liquid equipment component

(4) If a leak in an equipment component, other than a heavy-liquid component, is detected by a means other than a portable monitoring instrument, the component must, before it is repaired, be inspected for leaks using a portable monitoring instrument that meets the requirements of subsection 5(1).

Exception

(5) Subsections (3) and (4) do not apply if an authorized official determines that the equipment component cannot be inspected before it is repaired without exposing any individual to immediate danger.

Flagging for repair

(6) An equipment component that has a significant leak but cannot be repaired within 15 days after the day on which the leak is detected, despite the operator’s attempt to repair the component using generally accepted best repair practices for the component, must be flagged for repair — either by attaching a tag to the component or by noting the need for the repair in an electronic tracking system — as follows:

Repairs — time limits for flagged equipment components

(7) An equipment component that has a significant leak and is flagged for repair under subsection (6) must be repaired

Valve with three significant leaks

(8) A valve, other than a control valve, that has three significant leaks in any period of 24 consecutive months must be replaced with a certified low-leaking valve or repacked with certified low-leaking valve packing within the period required by subsection (1).

Exception

(9) Subsection (8) does not apply in respect of a valve for which no certified low-leaking valve and no certified low-leaking valve are commercially available.

Completed repairs

(10) The repair of the equipment component is considered to be completed when, following the repair,

Record keeping

9 (1) The operator must, for each calendar year, keep a record of the following information:

Requirements — photographs and video recordings

(2) The operator must, in addition to the record referred to in subsection (1), keep the following optical gas-imaging records for each calendar year:

Retention period

10 The operator of a facility must retain the inventory of equipment components referred to in paragraph 3(2)(a) and the records referred to in section 9, as well as any supporting documents, at the facility for at least five years after the inventory is established or updated or the records are created.

Requirements for Certain Equipment Components

Responsibilities of operator

11 The operator of a facility must ensure that the equipment components at the facility meet the requirements set out in sections 12 to 15.

Pipes

12 (1) The ends of a pipe that is not located in an emergency shutdown system must be plugged at all times using a method that minimizes, to the extent possible, the release of VOCs into the environment, including the use of a cap, a blind flange or a plug or the use of two valves that are operated so that the valve on the process fluid end is closed before the other valve is closed.

Non-application to certain pipes

(2) Subsection (1) does not apply in respect of a pipe that comes into contact with a fluid that would autocatalytically polymerize or would create any other safety hazard, if the pipe were plugged in accordance with that subsection.

Non-application during certain operations

(3) Subsection (1) does not apply during an operation that requires the ends of a pipe to be open.

Sampling systems

13 Every sampling system that is connected to a pipe must be designed and used in a manner that minimizes, to the extent possible, the release of VOCs into the environment. The design may consist of a closed-purge, closed-loop or closed-vent system.

Pressure relief devices

14 (1) Every pressure relief device must be designed and used in a manner that minimizes, to the extent possible, the release of VOCs into the environment. The design may consist of the installation of a rupture disk upstream of the pressure relief device or the installation of a closed-vent connection between the pressure relief device and a process gas system, a fuel gas system or a control device.

Requirement following pressure release

(2) If a pressure release occurs, the pressure relief device must, not more than five days after the day on which the release ends, be returned to a condition that minimizes, to the extent possible, the release of VOCs into the environment.

Centrifugal compressors

15 (1) Every centrifugal compressor must be equipped with a mechanical seal system that has a barrier fluid system.

Seal system

(2) The mechanical seal system of the compressor must be

Barrier fluid

(3) The barrier fluid in the barrier fluid system must contain less than 10% VOCs by weight, as determined in accordance with ASTM International standard E260, Standard Practice for Packed Column Gas Chromatography, or E169, Standard Practices for General Techniques of Ultraviolet-Visible Quantitative Analysis, or in accordance with other generally accepted engineering practices.

Sensor required

(4) The barrier fluid system must be equipped with a sensor that is intended to detect any failure of the system.

Sensor check

(5) The sensor must be checked daily to determine whether there has been a failure of the barrier fluid system, unless the sensor is equipped with an audible alarm for the purpose of indicating such a failure or a mechanism that shuts down the compressor in the event of such a failure.

Exception

(6) The requirements of this section do not apply in respect of a centrifugal compressor that is equipped with a closed-vent system designed to capture any leakage from the compressor drive shaft and transport it to a process gas system, a fuel gas system or a control device.

Record keeping

16 (1) The operator must, for each calendar year, keep a record of the following information:

Retention period

(2) The operator must retain the record, as well as any supporting documents, at the facility for at least five years.

Fenceline Monitoring Requirements

Standard fenceline monitoring program

17 (1) Subject to subsections (2) and (3), the operator of a facility must, not later than January 1, 2022, establish and maintain for the facility a standard fenceline monitoring program, in accordance with sections 18 to 25 and 28, that consists of the collection of samples — using sampling tubes — and the analysis of those samples, in order to measure the concentrations at the fenceline of each substance set out in Schedule 2.

Modified or alternative fenceline monitoring program

(2) The operator of a facility may, instead of the standard fenceline monitoring program referred to in subsection (1), establish and maintain for the facility one of the following programs in order to measure the concentrations at the fenceline of each substance set out in Schedule 2:

Time limit

(3) A program referred to in paragraphs (2)(a) or (b) must be established not later than six months after the permit for the program is issued.

Establishment after application for permit

(4) If an application for a permit to establish a modified or alternative fenceline monitoring program for a facility is received by the Minister on or before January 1, 2021 or, in the case of a facility that begins operating on or after December 1, 2020, not later than 30 days after the day on which the facility begins operating, the operator of the facility is not required to establish a fenceline monitoring program until 6 months after the day on which the Minister issues the permit under subsection 26(3) or 27(3), as applicable, or a notification under subsection 26(4) or 27(4), as applicable, that no permit will be issued for the modified or alternative program.

Establishment of standard fenceline monitoring program despite issuance of permit

(5) Despite being issued a permit for a modified or alternative fenceline monitoring program in respect of a facility, the operator may establish and maintain a standard fenceline monitoring program for that facility in accordance with subsection (1) if they give 30 days notice in writing to the Minister of their intention to do so, together with a standard fenceline monitoring plan containing the information referred to in paragraphs 31(1)(a) to (d).

Selection of fenceline

18 The operator may select either the property boundary of the facility or an internal monitoring perimeter as the fenceline for the purpose of the fenceline monitoring program. If an internal monitoring perimeter is to serve as the fenceline, it must be established in accordance with sections 8.2 to 8.2.3.2 of EPA Method 325A, except that tailings ponds and mining areas are to be excluded from the emission sources encompassed by the fenceline.

Selection of sampling equipment and supplies

19 (1) The sampling equipment and supplies must be selected in accordance with sections 6.1 to 6.4 of EPA Method 325A.

Sampling tubes

(2) Sampling tubes must meet the specifications set out in section 3.8 of EPA Method 325A.

Sorbent

(3) The sorbent used in the sampling tubes must be selected in accordance with sections 7.1 to 7.1.6 of EPA Method 325B.

Sampling locations

20 The number of sampling tubes and their location at the fenceline must be established in accordance with sections 8.1 to 8.2.3.2 of EPA Method 325A.

Deployment of sampling tubes

21 (1) The sampling tubes must be deployed at the facility fenceline in accordance with the procedures set out in sections 8.5 to 8.5.10 and 9.3 to 9.3.2 of EPA Method 325A, with the following modifications:

Collection of sampling tubes

(2) The sampling tubes deployed at the fenceline must be collected in accordance with the procedures set out in sections 8.6 to 8.6.5 of EPA Method 325A and must all be collected on the same day and, subject to subsection 24(3), every 13 to 15 days.

Continuous sampling

(3) When sampling tubes are collected at the fenceline in accordance with subsection (2) on any day, the subsequent deployment of sampling tubes must be carried out on the same day, so that the sampling is continuous.

Storage of sampling tubes

22 Sampling tubes must be stored in accordance with the procedures set out in sections 6.4 to 6.4.2 of EPA Method 325B.

Analysis of samples

23 The analysis of all samples collected under the fenceline monitoring program for the purpose referred to in subsection 17(1) must meet the following requirements:

Condition for less frequent analysis

24 (1) If the concentration of a substance set out in Schedule 2 remains below the method detection limit for that substance in 52 consecutive samples collected at each location at the fenceline in accordance with section 21, samples subsequently collected at each of those locations may be analyzed for that substance, in accordance with section 23, only twice per calendar year and, in that case, the interval between each collection of the samples to be analyzed for that substance in a calendar year must be at least five months, but not more than seven months.

Return to original analysis frequency

(2) Despite subsection (1), if the concentration of the substance in any sample analyzed at the frequency referred to in that subsection is above the method detection limit for that substance, every sample subsequently collected at each location must be analyzed for that substance in accordance with section 23.

Condition for less frequent collection

(3) If the concentration of each substance set out in Schedule 2 remains below the method detection limit for that substance in 52 consecutive samples collected at each location at the fenceline in accordance with section 21, samples may subsequently be collected at each of those locations only twice per calendar year and, in that case, samples must be collected at least five months, but not more than seven months, after the most recent collection of a sample.

Return to original collection frequency

(4) Despite subsection (3), if the concentration of a substance set out in Schedule 2 is above the method detection limit for that substance in any sample collected in accordance with that subsection, samples must subsequently be collected in accordance with subsection 21(2).

Meteorological data

25 (1) The meteorological data referred to in section 8.3.4 of EPA Method 325A must be collected at a meteorological station in accordance with that section. The meteorological station must be located at the facility, or within 40 kilometres of the fenceline, and must be operated in accordance with sections 8.3 to 8.3.3 of EPA Method 325A.

Calibration of meteorological instruments

(2) The calibration procedures set out in sections 2.5 to 2.5.2.6, 3.4 to 3.4.2, and 7.5 of the standard of the Environmental Protection Agency of the United States entitled Quality Assurance Handbook for Air Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final) (EPA-454/B-08-002) must be followed for the meteorological instruments at the meteorological station.

Application for permit — modified fenceline monitoring program

26 (1) The operator of a facility who wishes to deviate from the standard fenceline monitoring program referred to in subsection 17(1) in relation to the selection of the fenceline, or the number of sampling tubes or their location at the fenceline, may apply to the Minister for a permit to establish and maintain a modified fenceline monitoring program for the facility.

Contents of application

(2) An application for a permit referred to in subsection (1) must contain the following information:

Conditions for issuing permit

(3) The Minister may issue a permit for a modified fenceline monitoring program, setting out the permitted deviations from the standard fenceline monitoring program for the facility, if the proposed modified fenceline monitoring program meets the following conditions:

Notification — no permit to be issued

(4) If the conditions referred to in subsection (3) are not met, the Minister must not issue the permit and must notify the operator to that effect.

Application for permit — alternative fenceline monitoring program

27 (1) The operator of a facility who wishes to deviate from the standard fenceline monitoring program referred to in subsection 17(1) in relation to any aspects other than, or in addition to, the selection of the fenceline or the number of sampling tubes or their location at the fenceline, may apply to the Minister for a permit to establish and maintain an alternative fenceline monitoring program for the facility.

Contents of application

(2) An application for a permit referred to in subsection (1) must contain the following information:

Condition for issuing permit

(3) The Minister may issue a permit for an alternative fenceline monitoring program, setting out the permitted deviations from the standard fenceline monitoring program for the facility, if the proposed deviations from the standard fenceline monitoring program do not render the alternative fenceline monitoring program less effective than the standard fenceline monitoring program in measuring the concentrations at the fenceline of the substances set out in Schedule 2.

Notification — no permit to be issued

(4) If the condition referred to in subsection (3) is not met, the Minister must not issue the permit and must notify the operator to that effect.

Record keeping — standard or modified fenceline monitoring program

28 (1) The operator of a facility must, for each calendar year in which it maintains a standard or modified fenceline monitoring program, keep a record of the following information:

Retention period

(2) The operator must retain the record, as well as any supporting documents, at the facility for at least five years.

Reporting Requirements

Information to be provided on request

29 The operator must, not later than 30 days after receiving a request from the Minister, submit to the Minister a copy of any record required to be kept by the operator under these Regulations.

Information to be submitted for existing facility

30 (1) The operator of a facility that was operating before December 1, 2020 must, not later than December 31, 2020, submit the following information to the Minister:

Information to be submitted for new facility

(2) The operator of a facility that begins operating on or after December 1, 2020 must, not later than 30 days after the day on which the facility begins operating, submit to the Minister, in respect of that facility, the information referred to in paragraphs (1)(a) to (e).

Updated information to be submitted

(3) If there is a change in any of the information referred to in subsection (1) or (2) in respect of a facility, the operator of the facility must, not later than five days after that change, submit the updated information to the Minister.

Standard fenceline monitoring plan for existing facility

31 (1) The operator of a facility that was operating before December 1, 2020 and in respect of which the Minister does not receive an application for a modified or alternative fenceline monitoring program on or before January 1, 2021 must, not later than January 1, 2022, submit to the Minister a standard fenceline monitoring plan for the facility that contains the following information:

Standard fenceline monitoring plan or application for new facility

(2) The operator of a facility that begins operating on or after December 1, 2020 must, not later than 30 days after the day on which the facility begins operating, submit to the Minister either a standard fenceline monitoring plan for the facility that contains the information referred to in paragraphs (1)(a) to (d), or an application for a modified fenceline monitoring program in accordance with subsection 26(1) or an alternative fenceline monitoring program in accordance with subsection 27(1).

Annual report beginning in 2023

32 (1) Beginnning in 2023 and ending in 2027, the operator of a facility must, on or before June 30 in each year, submit a report to the Minister that contains the information required by sections 33 to 41 in respect of the facility for the preceding calendar year.

Annual report beginning in 2028

(2) Beginning in 2028, the operator of a facility must, on or before June 30 in each year, submit a report to the Minister that contains the information required by subsections 33(1) and (3) and 34(1) and (3) and sections 35 to 41 in respect of the facility for the preceding calendar year.

Heavy-liquid equipment components — three inspections

33 (1) The annual report must contain, with respect to the heavy-liquid equipment components that are required to be inspected visually three times per calendar year under paragraph 6(1)(a) and that are set out by type in Schedule 1, the following information with respect to those inspections for each of those types of equipment components:

Heavy-liquid equipment components — one inspection

(2) The annual report must contain, with respect to the heavy-liquid equipment components that are required to be inspected visually once per calendar year under paragraph 6(2)(a) and that are set out by type in Schedule 1, the following information with respect to those inspections for each of those types of equipment components:

Heavy-liquid equipment components — other detections

(3) The annual report must contain, with respect to the heavy-liquid equipment components that are listed in the inventory referred to in paragraph 3(2)(a) and that are set out by type in Schedule 1, the following information for each of those types of equipment components:

Gas and light-liquid equipment components — three inspections

34 (1) The annual report must contain, with respect to the gas and light-liquid equipment components that are required to be inspected three times per calendar year under paragraph 6(1)(b) and that are set out by type in Schedule 1, the following information with respect to those inspections for each of those types of equipment components:

Gas and light-liquid equipment components — one inspection

(2) The annual report must contain, with respect to the gas and light-liquid equipment components that are required to be inspected once per calendar year under paragraph 6(2)(b) and that are set out by type in Schedule 1, the following information with respect to those inspections for each of those types of equipment components:

Gas and light-liquid equipment components — other detections

(3) The annual report must contain, with respect to the gas and light-liquid equipment components that are listed in the inventory referred to in paragraph 3(2)(a) and that are set out by type in Schedule 1, the following information for each of those types of equipment components:

Valves with three significant leaks

35 The annual report must indicate, with respect to the valves that are listed in the inventory referred to in paragraph 3(2)(a) and that are set out by type in items 1 to 3 of Schedule 1, the number of each of those types of valves

Equipment components exempt from certain inspections

36 The annual report must indicate

Reasons for no inspection

37 The annual report must indicate the identification number of each equipment component listed in the inventory that was not inspected in accordance with subsection 6(1) or (2), as applicable, and the reasons why it was not inspected in accordance with the applicable subsection.

Reasons for no inspection before repair

38 The annual report must indicate, with respect to each equipment component that was not inspected before it was repaired because an authorized official determined, under subsection 8(5), that it could not be inspected without exposing any individual to immediate danger, the identification number of the component and the reasons for that determination.

Significant leak not repaired within 15 days

39 The annual report must contain, with respect to each equipment component that was not repaired within 15 days after the day on which a significant leak was detected in the component, the following information:

Estimated VOC releases by type of component

40 (1) The annual report must indicate, with respect to the equipment components that are listed in the inventory referred to in paragraph 3(2)(a) and that are set out by type in Schedule 1, the estimated total quantity of VOCs — expressed in kilograms — that is released by each type of equipment component during the calendar year that is the subject of the report. The quantity is to be calculated in accordance with the instructions set out in Schedule 3.

Estimated VOC releases by all components

(2) The annual report must indicate the estimated total quantity of VOCs — expressed in kilograms — that is released during the calendar year that is the subject of the report by the equipment components of all types, which is to be calculated by adding together the estimated total quantity of VOCs released that year by each type of component referred to in subsection (1).

Monitoring data — standard or modified fenceline monitoring program

41 If the facility maintained a standard or modified fenceline monitoring program during the calendar year that is the subject of the annual report, that report must contain the following information in respect of the program:

Auditor’s report to be submitted in 2024

42 (1) The operator of a facility must, on or before June 30, 2024, submit to the Minister a report prepared by an auditor that assesses the operator’s compliance with these Regulations in respect of the facility during the preceding two calendar years.

Auditor’s report beginning in 2028

(2) The operator of a facility must, on or before June 30 of every fourth year, beginning in 2028, submit to the Minister a report prepared by an auditor that assesses the operator’s compliance with these Regulations in respect of the facility during the preceding four calendar years.

Contents

(3) The auditor’s report must contain the following information:

Signature

(4) The auditor’s report must be signed by a licensed member of an engineering or scientific professional organization who is

Corrective action plan

43 If the auditor’s report referred to in subsection 42(1) or (2), as applicable, identifies any requirements of these Regulations with which the operator failed to comply in respect of the facility, the operator must submit to the Minister, together with that report, a corrective action plan that sets out the measures that the operator has already taken or plans to take in order to meet those requirements.

Independent auditor with no conflict of interest

44 (1) The audit must be conducted by an individual or a firm that

Qualifications of auditing individual

(2) If the audit is conducted by an individual, including an individual who is a member of a firm, the individual must

Qualifications of auditing members of a firm

(3) If the audit is conducted by two or more individuals who are members of a firm, each requirement set out in subsection (2) must be met by at least one of those individuals.

Format of applications, reports and plans

45 (1) An application made under these Regulations and a report or plan required by these Regulations must be submitted electronically in the format specified by the Minister and must bear the electronic signature of an authorized official.

Non-electronic format for reports and plans

(2) If the Minister has not specified an electronic format, or if it is impractical to submit the application, report or plan electronically in accordance with subsection (1) because of circumstances beyond the operator’s control, the application, report or plan must be submitted on paper in the form specified by the Minister and be signed by an authorized official. However, if no form has been specified, it may be in any form.

Related Amendment

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

Item

Column 1

Regulations

Column 2

Provisions
31 Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector)
  • (a) paragraphs 3(2)(a), (b), (c) and (e)
  • (b) section 11

Coming into Force

December 1, 2020

47 (1) Subject to subsections (2) and (3), these Regulations come into force on December 1, 2020.

January 1, 2022

(2) Sections 3 to 10 come into force on January 1, 2022.

January 1, 2023

(3) Sections 11 to 16 come into force on January 1, 2023.

SCHEDULE 1

(Paragraph 4(2)(b), sections 33 to 36, subsection 40(1) and section 2 of Schedule 3)

Types of Equipment Components for Inventory and Annual Report

SCHEDULE 2

(Subsections 17(1) and (2), paragraph 23(e), subsections 24(1), (3) and (4), paragraphs 26(2)(e) and (3)(b) and 27(2)(c), (e) and (f), subsection 27(3), subparagraph 28(1)(c)(i) and paragraphs 28(1)(d) and 41(c) and (d))

List of Substances for Fenceline Monitoring Program

SCHEDULE 3

(Subsection 40(1))

Instructions for Calculating Estimated VOC Releases

1 The following definitions apply in this Schedule.

pegged,
in respect of a reading on a portable monitoring instrument, means a reading indicating that the concentration of VOCs is above the highest concentration of VOCs that the instrument is capable of measuring. (arrimée)
screening value or SV
means the measured concentration of VOCs, expressed in ppmv, that is determined in the course of the inspection of an equipment component using a portable monitoring instrument. (concentration mesurée ou CM)

2 For the purpose of subsection 40(1) of these Regulations, the estimated total quantity of VOCs, expressed in kilograms, that is released by a type of equipment component set out in Schedule 1 during the calendar year that is the subject of the annual report is calculated by adding together the estimated quantity of VOCs that is released by each component of that type in that year and that is determined in accordance with section 4.

3 (1) Subject to subsections (2) and (3), the hourly leak rate — expressed in kilograms per hour (kg/hr) — of an equipment component of a type set out in column 1 of the table to this Schedule is:

(2) Subject to subsection (3), the hourly leak rate of a minor assembly of a type set out in column 1 of the table to this Schedule is:

(3) The hourly leak rate of a heavy-liquid equipment component of a type set out in column 1 of the table to this Schedule is:

(4) For the purpose of subsections (1) to (3),

4 The estimated quantity of VOCs, expressed in kilograms, that is released by an equipment component during the applicable calendar year is determined by adding together the hourly leak rates for that equipment component, as determined in accordance with section 5, for every hour in that calendar year.

5 (1) For the purpose of section 4, for every hour in the applicable calendar year, the hourly leak rate is the rate determined under section 3 that is based on the inspection carried out closest to that hour, whether that inspection took place in that calendar year or in the preceding or subsequent calendar year.

(2) If the number of hours between the hour referred to in subsection (1) and the preceding inspection is the same as the number of hours between that hour and the subsequent inspection, the hourly leak rate is the rate based on the preceding inspection.

(3) Despite subsection (1), if an inspection indicates that there is a significant leak in the equipment component, the hourly leak rate is determined on the basis of that inspection for every hour in the period beginning with the hour in which the inspection took place and ending with the hour before the hour in which the equipment component was repaired.

EQUIPMENT COMPONENT HOURLY LEAK RATES
Item

Column 1

Type of Equipment Component

Column 2

Hourly Default Zero Leak Rate (kg/hr per equipment component)

Column 3

Hourly Pegged Leak Rate
(kg/hr per equipment component)

Column 4

Hourly Correlation Equation Leak Rate (kg/hr per equipment component)
Hourly Leak Rates for Process Units Primarily Engaged in Activities Under NAICS Code 325 (Chemical Manufacturing)
1 Gas valve 6.60E-07 0.11 1.87E-06 × SV0.873
2 Light-liquid valve 4.90E-07 0.15 6.41E-06 × SV0.797
3 Heavy-liquid valve 4.90E-07 0.15 n/a
4 Compressor, pressure relief device, agitator, light-liquid pump 7.50E-06 0.62 1.90E-05 × SV0.824
5 Heavy-liquid pump 7.50E-06 0.62 n/a
6 Connector (other than a flange) 6.10E-07 0.22 3.05E-06 × SV0.885
7 Flange 3.10E-07 0.084 4.61E-06 × SV0.703
8 Open-ended pipe 2.00E-06 0.079 2.20E-06 × SV0.704
9 Gas minor assembly 1.65E-05 0.11 n/a
10 Light-liquid minor assembly 1.23E-05 0.15 n/a
11 Heavy-liquid minor assembly 1.23E-05 0.15 n/a
12 Any equipment component other than one referred to in items 1 to 11 4.00E-06 0.11 1.36E-05 × SV0.589
Hourly Leak Rates for All Other Process Units
13 Gas valve 7.80E-06 0.14 2.29E-06 × SV0.746
14 Light-liquid valve 7.80E-06 0.14 2.29E-06 × SV0.746
15 Heavy-liquid valve 7.80E-06 0.14 n/a
16 Light-liquid pump 2.40E-05 0.16 5.03E-05 × SV0.610
17 Heavy-liquid pump 2.40E-05 0.16 n/a
18 Connector (other than a flange) 7.50E-06 0.03 1.53E-06 × SV0.735
19 Flange 3.10E-07 0.084 4.61E-06 × SV0.703
20 Open-ended pipe 2.00E-06 0.079 2.20E-06 × SV0.704
21 Minor assembly 1.95E-04 0.14 n/a
22 Any equipment component other than one referred to in items 13 to 21 4.00E-06 0.11 1.36E-05 × SV0.589

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Issues: Releases of volatile organic compounds (VOCs), including petroleum and refinery gases (PRGs), from facilities in the petroleum and petrochemical sectors pose health and environmental risks to Canadians. The primary source of fugitive VOC releases is leaks from process equipment components.

The current regulatory and non-regulatory measures in place to limit fugitive VOC releases in the petroleum and petrochemical sectors could allow leaks to continue for long periods of time before they are detected and repaired.

Description: The Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector) [the Regulations] will require the implementation of comprehensive leak detection and repair (LDAR) programs at Canadian petroleum refineries, upgraders and certain petrochemical facilities. The operators of these facilities will also be required to ensure that certain equipment components are designed and operated in a manner that prevents leaks, and to monitor the level of certain VOCs at facility fencelines. The Regulations also include requirements for record keeping, reporting and third-party auditing.

Rationale: Existing LDAR programs involve just one inspection per component per year in many cases, though the number of baseline inspections varies across the country due to voluntary codes of practice (e.g. CCME, CFA), and provincial and municipal requirements (e.g. Ontario, Metro Vancouver). If a leak begins shortly after an annual inspection, it could continue to release VOCs, including PRGs, for over an entire year, depending on the timing of the next inspection. The VOC Regulations address this issue by requiring more inspections per year and a requirement to fix leaks that are quantified as being over a certain magnitude, thereby reducing the duration over which significant leaks could persist. In addition, the equipment modification provisions require a subset of components to be upgraded to meet standards designed to minimize releases of VOCs into the environment. Overall, the Regulations will reduce fugitive VOC releases by approximately 90 kilotonnes (kt) and greenhouse gas (GHG) emissions by 120 kt carbon dioxide equivalent (CO2e) for the years 2021 to 2037. This would result in improvements in human health and environmental quality, as well as benefits to businesses from recovered products. The present value (PV) of benefits is estimated at about $249.8 million (M), while the PV of costs is estimated at about $248.3M, yielding a net benefit of $1.5M. The Regulations are designed to harmonize, where possible, with the regulatory requirements of other jurisdictions, including provinces and the United States. The Regulations will also adopt a single-window reporting approach, where possible, to minimize the administrative burden on facilities.

Issues

Releases of VOCs, including PRGs, from process equipment components in the petroleum and petrochemical sectors contribute to the formation of smog and thus air pollution in Canada. Air pollution has been shown to have a significant adverse impact on human health, including premature deaths, hospital admissions and emergency room visits. Studies indicate that air pollution is associated with an increased risk of lung cancer and heart disease. In addition to smog formation, PRGs can contain carcinogenic VOC substances such as 1,3-butadiene, benzene and isoprene.

Most existing mandatory or voluntary measures for managing VOC releases focus on controlling large leaks from certain types of equipment components. However, smaller leaks are also an issue, because even low concentrations of the carcinogenic components of PRGs can cause harm to humans, and the aggregation of many small leaks can lead to significant volumes of VOC releases. The existing measures could allow leaks to continue for long periods of time before they are detected and repaired due to the relatively low frequency of inspections in many cases.

Background

Petroleum and refinery gases are released as part of mixed streams of VOCs in fugitive leaks from process equipment components in the petroleum and petrochemical sectors.footnote 2 According to the 2014 National Pollutant Release Inventory (NPRI) data for the affected refineries, approximately one third of total VOC emissions are fugitive emissions from process equipment. Other sources of VOC releases at facilities in these sectors include wastewater treatment systems, storage tanks, and emissions from stacks.

Petroleum and refinery gases and carcinogens

The Chemicals Management Plan (CMP) is a Government of Canada initiative aimed at reducing the risks posed by chemicals to Canadians and the environment. One such group of chemicals consists of PRGs, which are a category of light hydrocarbons produced by facilities such as refineries and upgraders. In 2013, 2014, and 2017, the Government of Canada (the Government) conducted peer-reviewed screening assessments of three different groups of PRGs and found that they can contain known carcinogenic substances such as (ARCHIVED) 1,3-butadiene, (ARCHIVED) benzene and (ARCHIVED) isoprene (substances that were assessed by the Government and determined to be harmful to human health).footnote 3 The NPRI reports that Canadian refineries, upgraders and petrochemical facilities release components of PRGs into the surrounding environment, including the carcinogens 1,3-butadiene, benzene and isoprene. It is expected that increased releases of carcinogenic substances from these facilities would increase cancer risks for Canadians in the vicinity of those facilities.footnote 4

1,3-Butadiene can damage the genetic information (e.g. DNA) within a cell and cause mutations, which may lead to cancer (genotoxicity). As well, 1,3-butadiene has been found to be a carcinogen in rodents and epidemiological studies have provided further evidence for an association between exposure to 1,3-butadiene and leukemia in humans. The assessment of 1,3-butadiene indicated that the investigation of options to reduce exposure for those in the vicinity of industrial sources should be a high priority.

Benzene is known to cause cancer, based on evidence from studies in both humans and laboratory animals. Studies examining the link between benzene and cancer have largely focused on leukemia and other cancers of blood cells. The assessment of benzene indicated that the examination of options to reduce exposure should be a high priority and that such exposure should be reduced wherever possible.

Similarly, it was concluded that isoprene was toxic to human health on the basis of carcinogenicity. The risk management objective for isoprene is to reduce exposure to isoprene from industrial emissions to the extent practicable.

The assessments concluded that PRGs were toxic to human health. It was recognized that a small portion of the general population may be exposed to these gases and their carcinogenic components in the vicinity of certain petroleum facilities. The human health objective for the management of PRGs is to minimize human exposure to the greatest extent practicable.

Volatile organic compounds

Petroleum and refinery gases belong to the broader category of VOCs, which are precursors to the formation of ground-level O3 and particulate matter (PM), the main constituents of smog. Both ground-level O3 and PM, in particular fine particulate matter smaller than or equal to 2.5 micrometres in diameter (PM2.5), have been shown to be detrimental to human health, and exposure to these pollutants increases the risks for a wide range of health problems.footnote 5

Exposure to ground-level O3 is associated with a variety of health effects, including premature mortality. Medical evidence is especially persuasive for the harmful effects of ground-level O3 on lung function and its contribution to respiratory symptoms and inflammation. There exists a significant association between short-term exposure to ground-level O3 and emergency room and hospital visits related to respiratory system problems (especially asthma-related) and premature mortality. Exposure to ground-level O3 could also result in some cardiac effects, adverse long-term respiratory impacts and chronic-exposure mortality.

Ground-level O3 may also interfere with the ability of sensitive plants to produce and store food, and increase their vulnerability to certain diseases, insects, harsh weather and other pollutants.

Epidemiologic evidence continues to confirm earlier observations of harm from PM and PM2.5.footnote 6 This includes confirmation of mortality from long-term exposure to PM2.5 and the link to adverse cardiac outcomes, both from acute and chronic exposures. Additionally, there is a robust relationship between PM2.5 and lung cancer mortality. Research suggests that PM2.5 is linked to morbidity through a range of adverse effects, including respiratory symptoms, bronchitis (both acute and chronic), asthma exacerbation and respiratory impacts. This results in a greater number of restricted activity days, emergency room visits, hospital admissions and premature mortality.

Several population groups are particularly susceptible to adverse effects following exposure to ground-level O3 and PM2.5. These include individuals who are more active outdoors, children, the elderly (especially those with a pre-existing respiratory or cardiac condition) and individuals who are hypersensitive to respiratory irritants. It is likely that the entire population is at some degree of risk even at the lowest concentration levels of ground-level O3 and PM2.5.

Particulate matter may also accumulate on surfaces and alter their optical characteristics. It can also reduce visibility by blocking and scattering the direct passage of sunlight through the atmosphere.

Affected facilities in the petroleum and petrochemical sectors

Twenty-five facilities will be subject to the Regulations. These facilities produce liquid petroleum products by means of processing (using distillation) crude oil or bitumen, mixtures of crude oil or bitumen and other hydrocarbon compounds, or partially refined feedstock derived from crude oil or bitumen. They include 18 petroleum refineries, five upgraders and two petrochemical facilities.

Eighteen refineries will be subject to the Regulations, one of which began operations in 2017. They are located in seven provinces, with the majority in Alberta and Ontario. These refineries produce transportation fuels, with gasoline being the major product, by processing conventional crude oil or synthetic crude oil (SCO). They also produce home heating oils, lubricants, heavy fuel oil, asphalt for roads, and feedstock for petrochemical plants. Most of these refined products serve the domestic market, but some are exported, mainly to the U.S.

There are five upgraders in Canada, four of which are located in Alberta and one in Saskatchewan. There was an additional upgrader in Alberta which shut down due to an explosion in 2016. It is not clear when this facility will resume its activities; therefore, it has been excluded from the analysis. Upgraders convert bitumen or heavy oil mainly into synthetic crude oil, but also into refined petroleum products such as diesel and kerosene.footnote 7 Most facilities are integrated or associated with oil sands extraction processes. The majority of SCO is exported to the U.S., although some is transported to domestic refineries.

Two petrochemical facilities that are operated in an integrated way with refineries or upgraders, one in Ontario and one in Alberta, will be subject to the Regulations. Petrochemical facilities convert refined petroleum feedstock, natural gas, or natural gas liquids into primary petrochemical products that are used to manufacture a variety of industrial and consumer products such as plastics. Petrochemical products include ethylene, styrene, propylene, benzene and butadiene. These products are either sold to domestic chemical manufacturing plants, or are exported (mainly to the U.S.).

Control of fugitive VOC releases in Canada

Leak detection and repair programs constitute the best practice for effectively controlling fugitive VOC releasesfootnote 8 from petroleum and petrochemical facilities, according to industry experience and the experience of other regulatory agencies. Most facilities affected by the Regulations have already implemented LDAR programs in some form.

In order to address VOCs as smog precursors, the Canadian Council of Ministers of the Environment (CCME) published a voluntary code of practice in 1993 (the CCME Code).footnote 9 This code aimed to establish a consistent method for the control of fugitive VOCs from leaking equipment components through LDAR programs. It recommends one inspection per year for most equipment components such as valves and pumps and four inspections per year for compressors, which have a greater likelihood of leaks. The CCME Code also recommends that portable monitoring instruments (“sniffers”) be used for inspection in accordance with the U.S. Environmental Protection Agency (U.S. EPA) Method 21.footnote 10 Under the CCME Code, a “significant leak” consists of the detection of a VOC concentration greater than or equal to 10 000 parts per million by volume (ppmv), measured at the source. The CCME Code recommends repair of significant leaks within 15 days of detection.

A number of provincial and municipal regulators, as well as an industry association, have subsequently used the CCME Code as a basis to develop their own control measures. For example, the Metro Vancouver Regional District has the same inspection requirements as the CCME Code, except that equipment components leaking at 1 000 ppmv or above must be repaired within 90 days of detection.footnote 11

The Quebec Clean Air Regulation requires quarterly inspections during the months of April to December for pumps, agitators and compressors, and annual inspections for other equipment components, with some exceptions.footnote 12 The significant leak threshold is 1 000 ppmv for equipment components containing any level of benzene or butadiene and 10 000 ppmv otherwise. If a leak contains 10% or more benzene or butadiene, then it must be repaired within 15 days of detection; leaks containing less than 10% of those substances must be repaired within 45 days.

The Ontario industry standards for petroleum refineries and petrochemical facilitiesfootnote 13 require three inspections per year for equipment components that are in contact with fluid containing certain levels of benzene or 1,3-butadiene. The threshold levels of benzene or 1,3-butadiene will be lowered over time, which will result in more equipment components being subject to inspection. The permitted time for repairing leaks of 1 000 ppmv or more depends on the leak concentration and is shortened over time. In addition, a sniffer must be used for at least one inspection per year, while optical gas imaging (OGI) cameras may be used for other inspections. In addition to LDAR, the standards require the concentration of benzene discharged from a refinery into the air, and the concentration of benzene and 1,3-butadiene discharged from a petrochemical facility into the air, to be measured. From six to twelve sampling locations must be installed at the facility to continuously sample the ambient air over a two-week period.

The Canadian Fuels Association (CFA) developed a voluntary code of practice for its members. It recommends an annual inspection of equipment components, with some exceptions, and the repair of any equipment components leaking at 10 000 ppmv or more within 90 days of detection.

Control of fugitive VOC releases in the United States

The U.S. EPA introduced LDAR requirements under the Clean Air Act in the mid-1980s. These requirements have been updated periodically and were revised significantly in 2007.footnote 14

Generally, U.S. petroleum refineries and petrochemical facilitiesfootnote 15 are required to conduct monthly inspections, with significant leak thresholds ranging from 500 ppmv (for most valves, connectors and pressure relief devices) to 2 000 ppmv (for most pumps). For certain types of equipment components, the inspection frequency (number of inspections) can be reduced if the number of leaks detected is consistently low. Repairs are required to be started within 5 days and completed within 15 days, unless the repair is not feasible without a process unit shutdown.

Since 2018, U.S. refineries have been required to implement a fenceline monitoring program to measure the concentration of benzene around the fenceline of the facility and to take corrective action if the concentration exceeds a defined threshold. The procedures for collecting and analyzing samples to determine the benzene concentration are set out in U.S. EPA Methods 325A and 325B.footnote 16,footnote 17

In addition to coming under the federal regulations, approximately 112 U.S. refineries are covered by consent decrees under the U.S. EPA’s Petroleum Refinery Initiative.footnote 18 These consent decrees include additional facility-specific measures to address VOC releases, including LDAR requirements that are more stringent than the federal regulations. Many states (including California, Texas and Louisiana) have also implemented their own regulations.

Objective

The objectives of the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector) are to

Description

In general, the Regulations will apply to petroleum refineries and upgraders, and to petrochemical facilities that are operated in an integrated way with those facilities. The Regulations will require that the operator of each affected facility

Concurrently with the Regulations, the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) [the Designation Regulations] are being amended.footnote 19 The amendment designates certain provisions in the Regulations that are subject to an increased fine regime for successfully prosecuted offences involving harm, or risk of harm, to the environment, or obstruction of authority.

LDAR program

The Regulations will require that facility operators implement an LDAR program, which will include maintaining an inventory of equipment components, undertaking inspections and repairing leaks.

Preventive equipment requirements

The Regulations will require that facility operators ensure that certain equipment components meet design and operating requirements in order to minimize releases into the environment.

Fenceline monitoring

The Regulations will require that facility operators establish sampling locations around the fenceline of the facility and perform sampling according to specific methods and timing. Operators can choose to follow the standard fenceline monitoring program outlined below, or submit an application for a modified or alternative fenceline monitoring program. Under the standard program, the requirements for quantity and location of the sampling locations, sample collection frequency and the sampling and laboratory analysis align with specific elements of U.S. EPA Methods 325A and 325B.

Other requirements

The Regulations will require that facility operators keep records and submit annual reports and third-party audit reports.

Regulatory development

Consultation

Over many years, stakeholders, Indigenous peoples and representatives of federal, provincial and municipal governments have engaged extensively in the development of measures to control the fugitive releases of VOCs and provided input during the assessments of PRGs under the CMP.

Early and prepublication consultations — 2003 to 2016

Consultations to review and update the CCME Code and to align it to the U.S. EPA’s regulatory measures began in 2003. Over the years, discussions among stakeholders brought about the understanding for the need to have a common strategy to reduce VOC releases from the petroleum and petrochemical sectors. The industry stakeholders in general were supportive of implementing a “smart” LDAR program that allows the use of OGI cameras to detect leaks. Further consultations in 2015 and 2016 led to the development of proposed Regulations for reducing fugitive emissions, published in May 2017.

Consultations on the proposed Regulations — May to July 2017

Proposed Regulations, along with a Regulatory Impact Analysis Statement describing the early and prepublication consultations, were published in the Canada Gazette, Part I, on May 27, 2017. This was followed by a 60-day consultation period. During this period, the Department received written comments from 25 organizations, including seven petroleum companies, four industry associations, four consultants and technology providers, three NGOs, three provincial governments, two municipal governments and two Indigenous peoples, i.e. the Aamjiwnaang First Nation and the Tsleil-Waututh Nation.

The Department met directly with several organizations to discuss their questions and comments. The Department also committed to considering input received after the end of the 60-day public comment period, and continued to meet with Indigenous peoples, provincial governments and industry until late 2017.

Provincial and municipal governments were generally supportive of the Regulations. Feedback from Indigenous peoples, industry, NGOs, consultants and technology providers focused on specific aspects of the proposal, and sought changes to certain requirements.

Key areas identified in the comments included the inventory of equipment components, fenceline monitoring, record keeping and reporting, auditing, and the timing of requirements coming into force. After consideration of the comments, the Department made several modifications to the Regulations and the cost-benefit analysis (CBA). Key changes are described in the comments and responses below.

Regulations

Comment No. 1: Affected facilities and sources

Indigenous peoples, provincial governments, and industry stakeholders asked why some facilities (e.g. chemical production facilities) were not subject to the Regulations, and inquired about addressing sources of VOC releases other than equipment leaks.

Response No. 1

One of the objectives of the Regulations is to address risks of PRGs, including components such as 1,3-butadiene, to the health of Canadians. As such, the Regulations target specific facilities and sources that are expected to release PRGs, based on the CMP screening assessments. Targeted facilities include petroleum refineries and upgraders, as well as petrochemical facilities that are operated in an integrated way with those facilities. Within the facilities, the targeted sources of releases are leaking equipment components.

While the Regulations are focused on facilities and sources that are expected to release PRGs, future regulatory initiatives could expand the scope to address additional VOC releases from other facilities and sources. For example, additional VOC release sources, including storage tanks and certain loading and unloading operations, have been identified in screening assessments for other petroleum substances under the CMP (such as natural gas condensates). The risk management approach document for natural gas condensates indicated that the Government is considering a regulation under CEPA for reducing fugitive and evaporative air emissions from sources not included in the Regulations (such as storage tanks and loading and unloading operations).

Comment No. 2: Scope of equipment components covered by the Regulations

Industry stakeholders recommended excluding small diameter equipment components, heavy-liquid equipment components and less accessible equipment components from the LDAR program. Industry stated that small diameter equipment components were time-consuming to inventory and contributed few emissions, that heavy-liquid equipment components contributed few emissions and were already inspected as part of daily operator walk-arounds, and that less accessible equipment components would be difficult to inspect. Industry recommended that equipment components wrapped in insulation or that are located more than two metres from a permanent fixed surface be inspected with the OGI camera unless there is a restricted view of the equipment component.

The industry stakeholders noted that should the proposed Regulations be adopted as drafted, their inventories would need to be updated and new equipment components added to the existing LDAR database. They also noted that adding these new equipment components could take a considerable effort and made proposals to reduce the workload. First, they proposed that flanges and connectors be included in the inventory using estimation methods rather than being given a unique identifier. In all cases, individual equipment components found to be leaking would be given a unique identifier to facilitate follow-up and leak repair. Secondly, they recommended the use of the word “relevant” instead of “accurate” in describing the inventory, and establishing the inventory as part of a management system (as opposed to requiring an accurate inventory).

Response No. 2

The Department considered information provided by industry on the percentage of emissions from small equipment components from a sample of U.S. refineries. The information showed that smaller (less than ¾ in. diameter) equipment components account for approximately one-third of equipment components inspected in an LDAR program and that these equipment components contribute from 10 to 25% of VOC emissions. Due to the contribution of emissions from the smaller equipment components, the Department continues to require them to be inspected as part of the LDAR program. The Department recognizes that existing inventories will increase when smaller equipment components are added and, therefore, has developed an effective method to include these equipment components in the LDAR program. The Regulations will allow up to 25 connected small diameter equipment components to be grouped and listed as a minor assembly in the inventory and will also allow a single inspection of the group with an OGI camera.

The Department recognizes that emissions from heavy-liquid equipment components are less than those from the same type of equipment components in gas or light-liquid service and that sniffers and OGI cameras do not effectively detect heavy-liquid leaks. To reflect this, the Regulations have been changed to require visual inspections for liquid drops from heavy-liquid equipment components. This change will reduce costs because neither a sniffer nor OGI camera is required to perform inspections.

Many equipment components will be difficult to inspect using a sniffer or OGI camera because they are covered in insulation or cannot be accessed from a fixed surface. To facilitate the inspection of these less accessible equipment components, the Regulations have been modified to allow equipment components covered in insulation to be inspected with an OGI camera at all locations where VOCs may escape including at end points or access points in the insulation. The Regulations have also eased the requirements regarding inspection of less accessible equipment components (those located more than two metres above a permanent support surface) to one inspection per year until December 31, 2026, in order to provide sufficient time for facilities to improve accessibility for these equipment components. Beginning in 2027, all equipment components will be required to be inspected three times per year.

Comment No. 3: Distribution of inspections throughout the calendar year

One First Nation commented that the proposed 90-day interval between the three annual inspections was appropriate because the inspections would be spread more evenly throughout the calendar year.

Industry stakeholders proposed that the 90-day interval between inspections would be challenging to comply with when maintenance outages and shutdown delays occur. As a result, they proposed that the time interval be reduced to 45 days.

Response No. 3

The Department considered the First Nation and industry comments and revised the Regulations to require that each of the three inspections occur at least one month but not more than six months after any previous inspection. This approach maximizes the time between inspections when ambient temperatures are within the operating range of the inspection equipment and increases opportunities to perform inspections around maintenance activities.

Comment No. 4: Estimation methodology if the leak is not measured before repair

Industry stakeholders suggested that operators should not be required to measure and quantify a leak prior to repairing it. They requested that the Department allow them to use the “pegged” value to quantify the leak.

Response No. 4

The Department considered estimating the concentration of leaks using the pegged value and determined that this could grossly overestimate emissions. However, the Department recognizes that it may not always be safe to measure the concentration of a leak before repair and has added an exception that a leak does not need to be quantified before repair, if the conditions are unsafe (e.g. if the leaking equipment component must be repaired immediately due to risk of fire or explosion).

Comment No. 5: Regulatory compliance timelines

Citing Ontario and U.S. experiences, industry stakeholders noted that six months is not a reasonable timeframe for compliance with the fenceline monitoring requirements. As a result, they proposed a compliance period of two years following the publication of the final Regulations in the Canada Gazette, Part II. The industry stakeholders also suggested that it could take one year to update the LDAR inventory to meet the requirements of the Regulations and that the preventive equipment requirements should be allowed a 36-month compliance timeline.

Response No. 5

The Department has maintained the requirement to implement the LDAR program within 18 months, as included in the proposed Regulations, as this would be considered sufficient time for industry to develop a complete inventory. However, to ease the transition for industry in implementing the program, the Regulations require less stringent repair requirements (10 000 ppmv rather than 1 000 ppmv) and less stringent inspections of equipment components that are difficult to inspect (once per year rather than three times per year) until December 31, 2026.

The Department revised the timeline to implement the standard fenceline monitoring program from 6 months to 18 months. This reflects time needed to plan monitoring locations in consultation with affected parties, installation of monitoring equipment and commissioning. Alternatively, if an operator has applied to the Minister for a modified or alternative fenceline monitoring program, the operator would have 6 months to implement the program after a permit is issued.

Comment No. 6: VOC definition and quantification

Industry stakeholders suggested using vapour pressure to define VOCs in the Regulations (similar to the definitions of “in heavy liquid service” and “in light liquid service” in the CCME Code). As an alternative, the industry stakeholders also suggested that the issue could be resolved by defining “heavy liquid” and exempting heavy-liquid equipment components from inspections.

Response No. 6

The Department modified the Regulations by adding definitions of “heavy liquid” and “light liquid” and excluding heavy-liquid equipment components from inspection using a sniffer or OGI camera. Instead, operators are required to undertake visual inspections of these equipment components. A leak of three drops per minute or greater from a heavy-liquid equipment component will be considered a significant leak.

Comment No. 7: Locating equipment components (GPS)

Industry stakeholders suggested that GPS is not an appropriate method for identifying the location of equipment components within a facility. They explained that they use piping and instrumentation diagrams and physical or visual tagging for locating equipment components. They were open to using photographs as a method of locating equipment components.

Response No. 7

The Department modified the Regulations so that the use of GPS to identify the location of equipment components is no longer required. Facilities are now required to record the location of equipment within the process unit using methods best suited to their facility.

Comment No. 8: Records of no-leak results from OGI cameras

Industry stakeholders saw no added value in keeping no-leak results from OGI cameras. They proposed that operators be allowed to develop a management system that ensures that inspections have been completed and can demonstrate completion without having to store all videos.

Response No. 8

Records are required to be kept for inspections performed with both a sniffer and an OGI camera. Records from a sniffer are in the form of a database of equipment components with the corresponding concentrations. Records from an OGI camera are in the form of a photo or video. The Department recognizes that more data storage is required to keep photos and videos compared to a database of concentrations. In order to minimize the costs associated with the increased data storage, the Regulations have been revised from requiring a video of each inspection (i.e. three videos per year for most equipment components) to requiring a photo of every inspection and a video of one inspection of each equipment component per year.

Comment No. 9: Fenceline monitoring — substances to be measured

Industry stakeholders indicated that the requirement in the proposed Regulations to measure the concentration of total retainable VOCs was confusing because there was not a defined procedure to determine this concentration in a laboratory. The industry stakeholders recommended that only benzene and 1,3-butadiene be measured at the fenceline because they can be measured using defined procedures and be compared with air quality standards.

Response No. 9

To increase clarity of the substances to be measured at the fenceline, the requirement to measure total retainable VOCs has been replaced with the requirement to measure benzene, ethylbenzene, 1,3-butadiene, toluene, m,p-xylene and o-xylene. These substances have established sampling tube uptake rates and laboratory analysis procedures.

Comment No. 10: Innovation and alternative technologies

Industry stakeholders, consultants and technology providers recommended that the Regulations allow for alternative approaches and technologies based on equivalent outcomes. They noted that LDAR and fenceline monitoring are emerging areas and recommended that the Regulations allow for government approval of an alternative approach.

Response No. 10

For LDAR, the Regulations allow the use of sniffers or OGI cameras, which have recently emerged as a proven technology for detecting leaks. The use of an OGI camera is widely supported by industry and the province of Ontario.

Regarding fenceline monitoring, the Regulations require the use of passive diffuse samplers to monitor the concentration of certain VOCs at the fenceline of a facility. The Regulations have been revised to add two further options for this monitoring. The first option is for the operator of a facility to apply to the Minister for a permit to implement a modified fenceline monitoring program. In a modified fenceline monitoring program, a different number and/or location of passive tube samplers at the fenceline can be permitted. The second option is for the operator to apply to the Minister for a permit for an alternative fenceline monitoring program. In an alternative fenceline monitoring program, alternative technology to measure the concentration of certain VOCs at the fenceline can be used. In both options, the fenceline monitoring program must be at least as effective in measuring concentrations of certain VOCs at the fenceline as the standard fenceline monitoring program.

Comment No. 11: Auditing requirements

Industry stakeholders did not support the requirements for an annual third-party audit, stating that this requirement would result in duplications in reporting, additional costs and a competitive disadvantage for Canadian facilities relative to their U.S. competitors. They recommended that the third-party audit requirements be removed from the Regulations.

Response No. 11

The Department reduced the burden on the industry by reducing the frequency of audits from annual to once every four years. Audits are typically performed at this frequency at refineries in the U.S.

Comment No. 12: Meteorological stations

Industry stakeholders noted that the proposed Regulations did not allow for a meteorological station to be shared between facilities. They contended that it is not necessary for a facility to maintain its own meteorological station if a common one is maintained in the area. They suggested that the Regulations be modified to allow the use of a meteorological station located within 40 km of the facility, for consistency with U.S. EPA regulations.

Response No. 12

The Department has revised the Regulations to allow the use of a meteorological station within 40 km of the facility. Regardless of its location, the meteorological station must meet the specifications set out in U.S. EPA Method 325A (e.g. calibration and standardization procedures for meteorological measurements).

Comment No. 13: Leak threshold

Industry stakeholders indicated that lowering the leak threshold to 1 000 ppmv from 10 000 ppmv (step-down) will cause substantial cost burden.

Response No. 13

In 2015, the Department recognized industry stakeholders’ comments that a leak threshold of 500 ppmv (being considered at the time) versus a leak threshold of 1 000 ppmv would result in small additional VOC reductions and higher repair costs (higher number of leaks identified means more repairs are required). Consequently, the Department revised the proposed leak threshold to 1 000 ppmv. The Department also recognized industry stakeholders’ comments in 2017 that a leak threshold of 1 000 ppmv versus a leak threshold of 10 000 ppmv would result in small additional VOC reductions and higher costs. To ease the requirements of the Regulations, a leak threshold of 10 000 ppmv until December 31, 2026, with a step-down to 1 000 ppmv thereafter has been adopted. These thresholds are less stringent than those in the U.S. As a result, implementing the step-down will not create a cost disadvantage for Canadian facilities.

Cost-benefit analysis

Comment No. 1: Estimated costs for equipment modifications

Industry stakeholders stated that the Department’s estimated costs for modifying equipment components to comply with the preventive equipment requirements were significantly underestimated. They proposed the following new estimates: from $200,000 to $800,000 for compressors without a closed-vent system or barrier fluid system; $800 for open-ended lines without a cap; and $20,000 to $85,000 for sampling connections not meeting the equipment requirement. No alternative modification cost was suggested for pressure relief devices.

Response No. 1

The Department conducted a literature review to verify the cost estimates that were used in the Canada Gazette, Part I (CGI) CBA for the proposed Regulations. Following this review, the Department agreed that the cost estimates published in CGI for modifying equipment did not adequately capture labour costs as well as other engineering costs (such as scaffolding, insulation, piping, demolition, contractor orientation, mobilization, permitting, and overhead costs). As a result, a Lang factor of 5.12 (obtained from Wolf, 2011) was used to adjust the CGI equipment costs to accommodate the additional costs. The adjusted equipment modification costs were fairly close to the industry stakeholders’ estimates.

Comment No. 2: OGI camera inspection rate

In the CBA for the proposed Regulations, the Department proposed an OGI camera inspection speed of 30 equipment components per minute, based on available reference studies. However, industry stakeholders indicated that this rate is too fast and proposed an OGI inspection speed of 1 to 3 equipment components per minute based on field experience.

Response No. 2

To address this feedback, the Department reviewed the inspection rate achieved at refineries in Ontario as part of a pilot project. The inspection rate from this study reflects the fact that in most inspections, more than one equipment component can be inspected at a time. In keeping with this, the Department considers a rate of 7 equipment components per minute as more realistic and reflective of field experience in Canada. This rate of inspection incorporates the difficultly to access certain equipment components because of the location or any other reasons, and includes overhead and prep time.

Consultation on the proposed Regulations — August 2017 to December 2019

Consultations with stakeholders and partners continued after the 60-day consultation period following publication in the Canada Gazette, Part I. Specifically, between August 2017 and December 2019, the Department held consultations with subnational governments, Indigenous partners, NGOs and industry stakeholders. In October 2019, all stakeholders and partners were informed to expect final publication of the Regulations in spring 2020. In response, some stakeholders informed the Department that they appreciated the efforts to finalize the Regulations, as this would ensure regulatory certainty. Below is a summary of the outcome of this consultation process.

Subnational governments

Throughout the consultation period, provincial and municipal governments have indicated general support for the Regulations. For instance, the Department discussed the Regulations through teleconferences with representatives from Alberta in October 2017, June 2018 and March 2019. In November 2017, the Department held a teleconference with representatives from Ontario, and has engaged further with them through collaborative projects on leak detection and repair and fenceline monitoring. Ontario indicated that the Regulations would be complementary to Ontario’s technical standards for petroleum refining and petrochemical production. The government of Saskatchewan and the municipalities of Montréal and Metro Vancouver have also supported the Regulations following the publication of the proposed Regulations. Provincial and municipal governments were provided with status updates by email in October 2018 and November 2019, but did not provide any further feedback.

Indigenous partners

Aamjiwnaang First Nation in Sarnia expressed their concerns with the delay of the final Regulations, and the health impact of air pollution from the neighbouring refineries and petrochemical facilities on the air quality in Sarnia. Tsleil-Waututh Nation indicated support for the Regulations, but recommended that other sources of VOCs such as storage tanks should be addressed as well. Tsleil-Waututh Nation and other Indigenous partners were provided with status updates of the Regulations in October 2018 and November 2019, but did not provide any further feedback.

Non-governmental organizations

Non-governmental organizations (Canadian Network for Human Health and the Environment, Saint John Citizens Coalition for Clean Air and Victims of Chemical Valley) indicated support for the Regulations following the publication of the proposed Regulations, but recommended that other sources of VOCs such as storage tanks be addressed as well. NGOs were provided with status updates by email in October 2018 and November 2019, but did not provide any further feedback.

Industry stakeholders

The Department consulted extensively with the Canadian Fuels Association, the Canadian Association of Petroleum Producers and the Chemical Industry Association of Canada to discuss their members’ comments on the Regulations and update them on the status of the Regulations. The Department received positive feedback in 2019 from the two main industry associations representing refineries and upgraders (Canadian Fuels Association and Canadian Association of Petroleum Producers) on how their members’ concerns would be addressed.

Modern treaty obligations and Indigenous engagement and consultation

An assessment of the geographical scope of the Regulations did not identify any potential modern treaty impacts, since no affected facility is located in a modern treaty area. The Regulations will result in incremental compliance costs for, and reductions in emissions from, refineries, upgraders, and petrochemical facilities. This regulatory action is not expected to negatively impact lands or resources covered by any modern treaties. However, as indicated above, consultations were held with Indigenous partners prior to and following the publication of the proposed Regulations in the Canada Gazette, Part I.

Instrument choice

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

Status quo

As indicated in the section "Control of fugitive VOC releases in Canada", most facilities have an LDAR program in place. However, many existing LDAR programs were developed based on the CCME Code published in 1993, which aims to reduce VOCs from large fugitive leaks. As well, the Code only focuses on certain types of equipment components and requires annual inspections for most of them, which could allow large leaks to continue for a long period of time before they are detected and repaired. Timely detection and repair of both small and large leaks is critical because even low concentrations of the carcinogenic components of PRGs can cause harm to human health. Hence, fugitive releases of VOCs, including PRGs, at those facilities must be further reduced. Therefore, maintaining the status quo is not a preferred option because it does not effectively address the risks of PRGs for Canadians in the vicinity of those facilities.

Code of practice

A code of practice was not considered as a potential instrument to further reduce fugitive VOC and PRG releases, as it is voluntary and not enforceable. It is not expected that all facilities would adopt a code of practice if it were to be developed as evidence shows that some facilities do not follow the existing CCME Code (two facilities have confirmed that they do not have an LDAR program in place). Therefore, it has been concluded that a code of practice would not result in the reductions of VOC and PRG releases that are necessary to adequately protect the health of Canadians.

Pollution prevention planning notice

Persons subject to a pollution prevention (P2) planning notice must prepare and implement a P2 plan that meets the requirements of the notice, must have their plan available on site and must carry out the actions identified in their plan. The implementation of P2 plans is enforceable, but their contents can vary because each plan is developed by an individual facility. Consequently, a P2 planning notice does not foster national consistency. As well, it does not guarantee the implementation of measures that are needed to minimize exposure to carcinogenic components present in PRGs to the greatest extent practicable, such as frequent inspections (e.g. three inspections per year) and preventive equipment requirements. Therefore, the Department concluded that a P2 planning notice was not the best instrument to achieve the objectives of the Regulations.

Market-based instruments

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

A cap and trade system was not considered to be an acceptable instrument, as setting a cap may suggest that there is a safe or acceptable amount of releases of carcinogens, which is not the case. The assessment of 1,3-butadiene indicated a high priority for investigation of options to reduce exposure for those in the vicinity of industrial sources. With a cap and trade system, it is not possible to control where the emission reductions will take place. It is determined by the markets; thus the objective of protecting Canadians in the vicinity of the affected facilities cannot be achieved by the cap and trade system.

Alternatively, fees and charges could be levied on facilities that emit VOCs above a threshold level. However, it would require a significant amount of time to configure them so that they provide the best incentive to industry. Furthermore, it would be costly and time-consuming to revise the fee structure as technology evolves. This approach was therefore also rejected.

Regulation

National regulatory requirements were considered to be the most practical and effective way to reduce fugitive VOC releases and thereby reduce exposure to PRGs and their carcinogenic components and protect human health. Being mandatory and uniform, regulatory measures will provide consistent fugitive VOC release control measures across affected facilities in the Canadian petroleum and petrochemical sectors, thereby achieving the objectives of the Regulations.

Regulatory analysis

Benefits and costs

The Regulations will reduce fugitive VOC releases from the affected facilities by about 90 kt and GHG emissions by about 120 kt CO2e, for the years 2021 to 2037. Reducing VOC releases will improve air quality by reducing primary precursors of smog (ground-level O3 and PM2.5). Better air quality results in improved human health, including reduced risks of premature mortalities and decreased cardiovascular system-related emergency room visits, valued by Health Canada at nearly $192M. Environmental benefits due to the reduction of VOC releases, such as increased agricultural productivity, reduced home cleaning expenditures and improved visibility, are valued at about $3M.

Other benefits include reduced human exposure to carcinogenic substances, GHG emission reduction and recovered products. Due to lack of data, the benefits associated with reductions in releases of carcinogenic substances are not quantified and monetized. However, a qualitative analysis is provided below. The benefit from GHG (primarily as methane) emission reduction is valued at about $6M. Methane is a component of many process streams at petroleum and petrochemical facilities; thus reducing fugitive VOC releases from these streams will also result in reduction of methane emissions.

Fugitive leaks result in the release of liquid hydrocarbons (e.g. crude oil and gasoline) to the atmosphere as VOC vapours. Consequently, facilities encounter economic losses of liquid hydrocarbon products when VOCs are released into the atmosphere. The inspection and repair of leaking equipment components would allow such products to be recovered for production or sale. The benefit of recovered fuel products is estimated to be around $49M.

In total, the benefits associated with the Regulations are estimated at about $249.8M.

To achieve these outcomes, facilities will need to implement an LDAR program, implement preventive equipment requirements, monitor the concentration of certain VOCs at the facility fenceline and undertake record-keeping and reporting activities. For the years 2021 to 2037, these actions will result in a total compliance cost of about $248.3M, including $191M for LDAR, $40M for equipment modification and maintenance, and $12M for fenceline monitoring. The Government will incur administrative costs of nearly $2M for compliance promotion and enforcement.

Overall, the Regulations will result in a net benefit to Canadians of about $1.5M.

Analytical framework

A CBA was conducted to assess the incremental impacts of the Regulations by comparing two scenarios. The business-as-usual (BAU) scenario assumes that facilities will continue to meet existing regulatory requirements or continue voluntary practices for controlling fugitive VOC releases. The regulatory scenario assumes that facilities will take the actions required by the Regulations. The differences in impact between the regulatory scenario and the BAU scenario are the incremental impacts of the Regulations.

The impacts of each scenario were assessed and quantified to the extent possible and are discussed in detail below. Benefits and costs are assessed for the 2021 to 2037 period.footnote 21 Dollar values are expressed in 2018 Canadian dollars and are discounted using a social discount rate of 3%. Unless otherwise specified, all results are presented cumulatively for the 2021 to 2037 period.

The logic model (Figure 1) explains the relationship between compliance with the Regulations and the incremental impacts (benefits and costs). Compliance with the Regulations will generate environmental and health benefits from reduced climate change impacts (due to reduced methane emissions) and improved air quality (due to reduced VOC emissions). Compliance with the Regulations will also result in recovered products (e.g. gasoline, synthetic crude oil, and ethylene) as a result of reduced leaks from the affected facilities. Sale of these products will provide additional production benefits. There are also possible health benefits due to reduced exposure to carcinogenic substances (such as 1,3-butadiene, benzene and isoprene) following reduced leaks. However, these benefits could not be quantified due to technical and data limitations.

Compliance with the Regulations will require the facilities to incur costs for LDAR (cameras, inspection, and repair), equipment modification, fenceline monitoring, and administrative costs. Likewise, the government will incur compliance promotion and enforcement costs. The cost impact on consumers is assumed to be negligible based on the competitiveness analysis in the section "Sensitivity analysis" below.

Figure 1: Logic model for the Regulations

Logic model to show the impacts from compliance with the Regulations, grouped by benefits and costs.

Assumptions, data and uncertainties

The modelling of benefits, costs and emissions was informed by extensive research and consultation with stakeholders and partners. Data were collected from a variety of Canadian and international government publications, databases, academic papers and submissions from industry sources. For example, industry stakeholders were consulted on key assumptions and data, and input was incorporated into the analysis to improve the estimates for equipment component inventories, as well as inspection, repair and administration costs.

The CBA was based on the best available information, and the central case represents just one possibility based on a conservative calibration of various input parameters. The sensitivity analysis presented below provides a range of possible outcomes reflecting the uncertainty around key variables. In cases where there was a lack of supporting data, the Department made reasonable assumptions. For example, detailed information pertaining to the fraction of equipment components that is leaking (leak fractions) and emission rates (the quantity of VOCs released to the atmosphere through the leak source, in terms of total kilograms per hour) at Canadian facilities for equipment components subject to an LDAR program was not available. Consequently, the Department estimated these data using the U.S. EPA Protocol for Equipment Leak Emission Estimates (PDF), a U.S. EPA report entitled Emission Factors and Frequency of Leak Occurrence for Fittings in Refinery Process Units and the Department’s technical expertise. Industry stakeholders were consulted on these estimates and provided leak fraction and emissions rate data; however, these data were incomplete.

Updates to the analysis following publication in the Canada Gazette, Part I

Following publication in the Canada Gazette, Part I, the Department engaged with stakeholders and partners to review modelling assumptions used in the analysis. Below is a summary of the main changes made to the analysis.

CBA assumption updates since the publication of the proposed Regulations in 2017

Other modelling updates

Models

As indicated above, a CBA model was developed to quantify and monetize benefits and costs and to estimate fugitive VOC releases (further detailed below) in the BAU and regulatory scenarios. Once fugitive VOC releases were estimated, A Unified Regional Air-Quality Modelling System (AURAMS) was used to determine changes in ambient air concentrations between the two scenarios. The Air Quality Benefits Assessment Tool (AQBAT) model of Health Canada was then used to estimate the health benefits. Similarly, the Department’s Air Quality Valuation Model 2 (AQVM2) was used to estimate the environmental benefits. These models are peer-reviewed.

Equipment components

The LDAR program set out in the Regulations applies to all equipment components that come into contact with a fluid that contains 10% or more VOCs by weight (subject to certain exceptions). This analysis considers the following types of equipment component:

The inventory of equipment components among facilities varies depending on production capacity, complexity of process units and the type of facility. For facilities that did not submit equipment component counts in response to a survey conducted by the Department in 2016, the analysis used average equipment component counts based on the RTI Memo. Equipment component inventories for upgraders are assumed to be the same as those for refineries. Equipment component counts submitted by facilities were adjusted for data gaps. A summary of inventory estimates is presented in Table 2. The RTI Memo classifies refineries based on their production capacity and classifies petrochemical facilities based on their “complexity” (an approach that takes into consideration the range of different process units present in the facilities). After receiving stakeholder input, the RTI Memo categories were modified as shown in the following table.

Table 2: Average equipment component counts
Source: Estimation based on the RTI Memo and stakeholder input.
Sector Production Capacity (barrels/day) / Complexity of Process Units table c2 note * Average Equipment Component Count Number of Facilities Location
Refineries > 200 000 104 457 2 1 in Que., 1 in N.B.
100 000 – 200 000 39 229 8 3 in Alta., 2 in Ont., 1 each in Que., Sask., N.L.
50 000 – 100 000 26 170 4 2 in Ont., 1 each in Alta. and B.C.
< 50 000 20 277 4 1 each in Alta., B.C., Ont. and Sask.
Upgraders ≥ 50 000 59 508 5 4 in Alta., 1 in Sask.
Petrochemical facilities Complex 15 174 1 1 in Alta.
Medium 5 467 1 1 in Ont.

Table c2 note

Table c2 note *

Refineries and upgraders are disaggregated by facility size, and petrochemical facilities by complexity.

Return to table c2 note * referrer

The number of equipment components for existing facilities is assumed to remain unchanged over time, because existing facilities are not expected to expand their production capacity. Across all affected facilities, the total estimated number of equipment components is approximately one million.

Business-as-usual scenario
Current LDAR programs

In the BAU scenario, affected facilities will continue to adhere to the LDAR programs currently in place. The determination of an individual facility’s current LDAR program is based on whether the facility is subject to LDAR requirements under operating permits, provincial regulations, or municipal by-laws. If no such information is available, it is assumed that existing facilities will follow a code of practice published by the Canadian Fuels Association (the CFA Code). However, the refinery in Alberta that began operations in 2017 is assumed to be subject to an operating permit that references the LDAR program based on the CCME Code, given that most facilities in the province are operating under similar permits. The Department received confirmation that no LDAR program is in place at two facilities. Table 3 provides a summary of LDAR programs at affected facilities and the section "Control of fugitive VOC releases in Canada" above describes specific LDAR program requirements.

Table 3: LDAR programs under the BAU scenario by province

Reference for LDAR Program

Province

Number of Facilities

CCME Code referred to in Operating Permits (13 in total)

B.C.

1

Alta.

 9

Sask.

 1

N.B.

 1

N.L.

 1

CFA Code of Practice (1 in total)

Alta.

1

Municipal by-law or provincial regulations and standards (9 in total)

B.C.

1

Que.

 2

Ont.

 6

No LDAR (2 in total)

Sask.

2
Leak detection and measurement

Industry stakeholders have indicated that, in most cases, contracted LDAR technicians conduct inspections. Based on the information collected, the technicians use a variety of methods to detect leaks. Some inspect equipment components using a sniffer, while others use an OGI camera to detect leaks and then a sniffer to measure leak concentrations.

Optical gas-imaging cameras are equipped with special filters that allow inspectors to detect and display methane and VOC gas plumes, which are invisible to the naked eye. The cameras are capable of scanning large areas in real time and identifying the source of a leak quickly. Various expert sources indicated that OGI cameras can scan between 1 800 and 2 300 equipment components per hour. In field use, OGI cameras are currently capable of detecting the majority of leaks of 10 000 ppmv or more. They are also capable of detecting smaller leaks in ideal weather conditions. With technology advancement and user training and experience, it is expected that by 2026, cameras will be able to detect the majority of leaks of 1 000 ppmv or more. In addition, given the rapid improvements in capability and reliability, it is expected that OGI cameras will be a widely used monitoring instrument in the future.

In this analysis, it is assumed that inspection will be conducted by LDAR technicians using an OGI camera to detect leaks, followed by the use of a sniffer to measure leak concentrations. In response to stakeholder feedback, and incorporating evidence from a pilot project in Ontario, it is assumed that a technician with an OGI camera could inspect seven equipment components per minute. On the other hand, a sniffer would require around two minutes per equipment component (based on experience from industry stakeholders and the U.S. EPA).

For facilities in Ontario, Quebec and the Metro Vancouver Regional District, where the significant leak threshold is 1 000 ppmv for certain equipment components, inspections are assumed to be conducted using a sniffer for those equipment components for the years 2021 to 2026, even though OGI cameras are permitted for most inspections in these jurisdictions. Starting in 2027, it is assumed that inspections at these facilities will be conducted using an OGI camera, when permitted.

It should be noted that for the purpose of simplicity, it is assumed that significant leaks are repaired as soon as they are detected. In the analysis, there is no time lag between leak detection and repair.

Performance incentive programs

The CCME Code recommends that, if the leak frequency (leak fraction) for a type of equipment component (e.g. flanges) is less than 2% in two or more successive inspections, a statistical sampling method may be used for that type of equipment component. As a result, a smaller number of equipment components will require inspection.

The Ontario industry standards for petroleum refineries and petrochemical facilities allow the inspection frequency to be reduced from three times to once per year if the percentage of leaking valves in the previous year is less than 1.0% and the average concentration of VOCs from leaking equipment components in the previous year is less than 10 000 ppmv.

There is evidence to suggest that some facilities are conducting inspections with statistical sampling. However, the Department’s estimated leak fractions are greater than 2% for all types of equipment components, except for connectors. For this reason, it is assumed that the statistical sampling method will not be used in the future. Had the statistical sampling method been incorporated into the analysis, the reduction of VOC releases and the costs would have been lower.

Significant leaks

The quantity of significant leaks, by type of equipment component, is determined by multiplying the equipment component count by the fraction of equipment components expected to be leaking at or above the significant leak threshold.

It is estimated that a total of 272 000 significant leaks will be detected and repaired in the baseline scenario over the period of analysis.

Estimation of fugitive VOC and methane releases

For each type of equipment component, the fugitive VOC releases are estimated by multiplying the equipment component count by the average emission rate for that type of equipment component.

In the U.S., the Refinery Emissions Protocol states that methane constituted up to 10% of VOCs emitted by leaking equipment components for which the refinery emission rates are based.footnote 24 Based on the Department’s technical expertise, it is assumed that methane constitutes 5% of the VOCs emitted from all types of facilities. One unit of methane is considered equivalent to 25 units of CO2 in terms of 100-year global warming potential (GWP).footnote 25 Thus, in the BAU scenario, it is estimated that a total of 120 kt of VOCs and 160 kt CO2e of GHG emissions will be emitted by all affected facilities for the years 2021 to 2037. Annual VOC releases in the BAU and the regulatory scenarios are shown in Figure 2 below.

Regulatory scenario
LDAR program

Under the regulatory scenario, facilities will be required to comply with the LDAR requirements described in the section "LDAR program." The Regulations will require three inspections per year for all equipment components in the inventory (with some exceptions), beginning on January 1, 2022.

For the period beginning on January 1, 2022, and ending on December 31, 2026, the Regulations will consider a significant leak as having a concentration of 1 000 ppmv or more for compressors and 10 000 ppmv or more for other gas or vapour and light-liquid equipment components. Beginning on January 1, 2027, the leak threshold will be 1 000 ppmv for all gas or vapour and light-liquid equipment components. Beginning on January 1, 2022, the leak threshold for heavy-liquid equipment components will be three drops per minute. The CBA assumes 100% compliance with these requirements.

Leak detection and measurement

It is assumed that facilities will continue to contract LDAR technicians to implement their LDAR programs. For gas or vapour and light-liquid equipment components, it is assumed that those technicians will use OGI cameras to detect leaks and sniffers to measure the concentration of detected leaks. The higher inspection frequency requirement will lead to more purchases of OGI cameras, which have substantially faster detection speeds than sniffers.

Just as in the BAU scenario, it is assumed that existing OGI cameras are not able to detect all leaks at a concentration below 10 000 ppmv. However, by 2027, imaging technology is assumed to have improved to the point where OGI cameras will be able to detect leaks as low as 1 000 ppmv. Considering that the regulatory leak threshold will drop in 2027, it is assumed that improved OGI cameras will be purchased for all facilities at that time.

For heavy-liquid equipment components, it is assumed that technicians will continue to conduct inspections visually.

Equipment modification and other requirements

The Regulations will impose preventive requirements for the design and operation of certain types of equipment components, including compressors, PRDs, OELs and sampling connections. Many of these equipment components already meet these requirements, but some will need to be modified. Equipment components meeting the requirements are assumed to leak at a concentration less than 500 ppmv.

The modifications, combined with more frequent inspections and repairs, are expected to reduce the total releases in the regulatory scenario.

Significant leaks and fugitive VOC releases

Approximately 1.2 million leaks will be detected and repaired in the regulatory scenario over the period of analysis, mainly as a result of the higher inspection frequency, the lower significant leak threshold and the broader range of types of equipment components in the Regulations.

It is estimated that a total of 30 kt of VOC releases and 40 kt CO2e of GHG emissions will be emitted by all affected facilities for the years 2021 to 2037 as shown in Figure 2 under the regulatory scenario.

Incremental impacts of the Regulations
Incremental benefits

The Regulations will reduce fugitive VOC releases by a total of about 90 kt. Releases from refineries will be reduced by 62 kt, from upgraders by 26 kt and from petrochemical facilities by nearly 2 kt. The Regulations will also reduce GHG emissions from methane leaks by a total of about 120 kt CO2e. This will include a reduction of 82 kt CO2e from refineries, 35 kt CO2e from upgraders, and nearly 3 kt CO2e from petrochemical facilities.

Figure 2: Fugitive VOC emissions (excluding methane) in the BAU and regulatory scenarios and compliance costs by year

Comparison of VOC emissions in the baseline and regulatory scenarios and discounted incremental costs, from 2021 to 2037. - Text version below

Figure 2 - Text version
Figure 2: Fugitive VOC emissions (excluding methane) in the BAU and regulatory scenarios and compliance costs by year
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037
Regulatory emissions (t) 7 625 3 940 2 061 2 060 2 051 2 051 1 782 1 782 1 782 1 782 1 782 1 782 1 782 1 782 1 782 1 782 1 782
Baseline emissions (t) 7 625 7 625 7 626 7 626 7 602 7 589 7 624 7 624 7 624 7 624 7 624 7 624 7 624 7 624 7 624 7 624 7 624
Discounted costs ($) 4,065,284 10,993,177 40,906,472 8,774,992 7,821,810 7,542,582 19,121,601 17,332,166 16,235,683 15,762,799 15,303,688 15,399,405 14,425,194 14,004,703 13,596,799 13,681,852 12,816,287

Health benefits from reductions of VOC releases

Extensive scientific research in Canada and around the world has shown that any incremental increase in air pollution exposure results in an increase in per capita risk of adverse health effects. The relationship between exposure to each pollutant (e.g. fine particulate matter or ozone) and increased risk has been quantified for individual health outcomes. Health Canada’s Air Quality Benefits Assessment Tool (AQBAT) incorporates those mathematical relationships along with data on Canadian populations to estimate the number of adverse morbidities and premature mortalities associated with a given incremental change in air pollution. In addition, AQBAT provides economic valuation estimates of those health impacts, considering the potential social, economic and public welfare consequences of the health outcomes, including medical costs, reduced workplace productivity, pain and suffering, and the impacts of increased mortality risk.

Over the period of analysis, it is estimated that air quality improvements from the Regulations will result in 34 fewer premature deaths. In addition, better air quality is expected to result in 6 897 fewer days of asthma symptoms among asthmatics and 33 654 fewer days of reduced activity and breathing difficulty among non-asthmatics. The total present value of health benefits resulting from air quality improvements under the Regulations is estimated at $191.4M.

As shown in Table 4, aggregate health benefits of the Regulations will be most significant in British Columbia, Quebec, Alberta and Ontario. Provincial health benefits reflect not only emission reductions, but also atmospheric conditions and population exposure to these pollutants. The provinces that experience the largest health benefits, in absolute terms, are the provinces with the largest populations and the highest levels of population exposure. Additionally, wind direction and atmospheric conditions play a critical role in smog formation and human exposure. Emission reductions at facilities that are located upwind of large population centres (e.g. Vancouver) can have a greater health impact than similar emission reductions at facilities in more remote locations, or in locations that are downwind of major population centres. As a result, health benefits by province are not directly proportionate to emission reductions by province.

Approximately 61% of the health benefits resulting from reducing VOC releases are associated with lower ambient levels of PM2.5 and 39% are a result of reductions in ground-level O3. Less than 1% is due to the reduction in levels of other pollutants captured in Health Canada’s model (AQBAT), including nitrogen dioxide (NO2).

Table 4: Cumulative health benefits associated with air quality improvements (2021–2037)
2017 million Canadian dollars, discounted to 2018, 3% discount rate
Province Number of Facilities Estimated Number of Selected Negative Health Outcomes Prevented by the Regulations Economic Value of Health Benefits, by Pollutant ($M)
Premature Mortalities Asthma Symptom Days Days of Restricted Activity in Non-Asthmatics PM2.5-related Annual and Summer Ground-Level O3 Total, All Pollutants
British Columbia 2 12 2,784 11,752 31.5 36.0 68.0
Quebec 2 9 1,196 8,453 42.6 8.1 50.9
Alberta 10 8 1,814 8,796 29.4 14.0 43.5
Ontario 6 4 980 3,985 9.8 13.8 23.7
Other 5 1 124 668 3.4 1.9 5.3
Canada 25 34 6,897 33,654 116.7 73.9 191.4

Totals may not add up due to rounding.

Health benefits of reductions in carcinogenic substances

The Regulations will reduce human exposure to toxic substances such as PRGs, 1,3-butadiene, benzene and isoprene. As noted in the assessments, Health Canada recommends reducing exposure to carcinogens like 1,3-butadiene and benzene wherever feasible. Therefore, although the benefits of these reductions were not quantified, they are expected to increase the overall health benefits estimated above.

Environmental benefits

Better air quality may result in increased crop yields and reduced soiling of surfaces from particulate deposition, as well as improvement in visibility, which may positively impact the general welfare of Canadians. As shown in Table 5, the quantified environmental benefits resulting from the Regulations are estimated to be about $3.3M. Higher crop yields and avoided household cleaning costs account for $1.2M and $0.5M, respectively. The welfare of residential households associated with improvement in visibility is valued at $1.6M. Alberta will receive the largest portion of these benefits, which is consistent with its larger reduction in VOC releases and the higher population density around the release sources. At the same time, environmental benefits in some provinces may be partly attributable to reductions of VOC releases from adjacent provinces, because pollutants can travel over longer distances.

Table 5: Cumulative environmental benefits by type of impact (2021–2037)
2017 million Canadian dollars, discounted to 2018, 3% discount rate

Province

Soiling

Avoided Costs for Households

Visibility

Changes in Welfare for Households

Agriculture

Changes in Sales Revenues for Crop Producers

Total
Alberta 0.13 0.43 0.39 0.95
Quebec 0.15 0.52 0.06 0.73
Ontario 0.10 0.29 0.27 0.66
Saskatchewan 0.01 0.06 0.39 0.46
British Columbia 0.13 0.23 0.01 0.37
Other 0.01 0.06 0.04 0.11
Canada 0.53 1.59 1.16 3.28

Totals may not add up due to rounding.

The above estimate for total environmental benefits should be considered to be conservative, because several benefits could not be quantified. The reduction in concentrations of ground-level O3 and PM may benefit the health of forest ecosystems, and may reduce the risks of illness or premature death within sensitive wildlife or livestock populations, which would potentially result in reduced treatment costs and economic losses for the agri-food industry. However, due to limitations in data and methodology, these benefits could not be quantified in the AQVM2 model.

Interpretation of modelled benefits

The above health and environmental modelling was conducted in 2018 to reflect the significant changes to regulatory requirements and input assumptions that arose after the initial publication, however minor changes to the start dates of the LDAR and equipment modification provisions occurred in 2019. Specifically, the modelled benefits assume a 2021 start date for LDAR and that the equipment modifications would occur in 2024. LDAR and equipment modifications will now occur in 2022 and 2023, respectively. The Department did not remodel these changes.

As a result of the delay in the LDAR start date, the equivalent emission reductions that result from that provision now occur one year later throughout the analytical period. If the Department were to remodel this change, the same reductions occurring later in time would produce greater health benefits due to increases in population. In addition, the change in the equipment modification provisions from 2024 to 2023 yielded even greater emission reductions than were modelled. For both of these reasons, the health and environmental benefits presented above should be interpreted as lower bound estimates.

Economic benefits from recovered products

When liquid hydrocarbons leak from petroleum and petrochemical facilities, they are transformed by changes in temperature and pressure into vapours. If the hydrocarbons had not leaked, the facility owners would receive profits from the sale of those hydrocarbons as final products. Therefore, repairing and modifying the equipment components that process VOCs will mitigate some of the economic losses associated with such leaks.

To assess the economic benefits from minimizing leaks, it is assumed that petroleum refineries will recover crude oil and gasoline, upgraders will recover diluted bitumen and synthetic crude oil, and petrochemical facilities will recover propane and ethylene. It is further assumed that a reduction in releases of VOCs of one tonne will result in the recovery of 1 000 L of liquid products.

Canada has a small, open economy and is a price taker in the world petroleum market. Any increase in recovered products resulting from the Regulations is therefore not expected to alter the price of petroleum. In addition, since Canada is a net exporter of petroleum products,footnote 26 recovered products resulting from the Regulations are expected to be redirected from domestic consumption to increased exports.

Using forecasted prices of recovered feedstock and fuel products from the Canada Energy Regulator and the E3MC model, the economic benefit from recovered products is estimated to be $49M.

The following tables provide the estimated quantities of recovered products and the price forecasts over the analytical period.

Table 6a: Estimated average annual quantities of recovered product by sector, million litres
Year 2022 2023–2027 2028–2032 2033–2037
Refineries
Gasoline 1.35 2.05 2.12 2.12
Crude oil 1.35 2.05 2.12 2.12
Upgraders
SCO 0.55 0.86 0.90 0.90
Bitumen 0.55 0.86 0.90 0.90
Petrochemical
LPG 0.04 0.05 0.06 0.06
Ethylene 0.04 0.05 0.06 0.06
Table 6b: Fuel price forecast, 2022–2037, 2017 Canadian dollars
Year 2022 2023–2027 2028–2032 2033–2037
Gasoline
Ontario 1.04 1.05 1.10 1.12
Quebec 1.02 1.03 1.08 1.09
British Columbia 1.18 1.19 1.24 1.26
Alberta 1.00 1.01 1.06 1.08
Saskatchewan 1.02 1.04 1.09 1.10
New Brunswick 0.97 0.98 1.03 1.05
Newfoundland and Labrador 1.07 1.09 1.14 1.16
Crude oil
WTI table d4 note * 0.53 0.54 0.57 0.57
Brent 0.56 0.57 0.60 0.60
SCO
WTI 0.53 0.54 0.57 0.57
Bitumen
WCS table d4 note ** 0.43 0.44 0.47 0.47
LPG
Alberta 0.31 0.32 0.34 0.35
Ontario 0.32 0.33 0.35 0.36
Ethylene
Alberta 0.73 0.74 0.77 0.79
Ontario 0.73 0.74 0.77 0.79

Table d4 note(s)

Table d4 note *

West Texas Intermediate

Return to table d4 note * referrer

Table d4 note **

Western Canadian Select

Return to table d4 note ** referrer

GHG emissions reduction benefits

The Regulations will reduce GHG emissions by about 120 kt CO2e through the repair of leaking equipment components and the modification of equipment components. Using the Technical Update to Environment and Climate Change Canada’s Social Cost of Greenhouse Gas Estimates, the benefits associated with this reduction are valued at about $6M.footnote 27

The central analysis assumes that the Regulations do not materially impact domestic consumption of recovered products and thus CO2e emissions from downstream combustion are not considered. However, it is possible that the recovered products are exported. The combustion of these products could lead to an increase or a decrease in CO2e emissions, depending on the energy source that is displaced. An alternative scenario in which downstream combustion displaces an energy source with a lower emission intensity is explored in the "Sensitivity analysis" section below.

Incremental costs

The total incremental costs of the Regulations are estimated to be $248.3M. These costs will occur largely as a result of more frequent inspections and repairs to equipment components.

Costs to industry

OGI cameras

Based on stakeholder feedback and other information, it is assumed that an OGI camera costs about $100,000 to purchase and that it has an annual maintenance cost of $2,000. For staff training, a one-time cost of $2,500 per camera will be carried by LDAR operators. It is assumed that there are 13 OGI cameras currently in use and that 12 additional OGI cameras will be purchased in 2022 to meet the higher inspection frequency requirements. A replacement set of 25 new cameras is expected to be purchased in 2026, which will be capable of detecting leaks at the reduced significant leak threshold of 1 000 ppmv. The cumulative costs of purchasing and maintaining OGI cameras, including staff training, are estimated to be $3.3M.

Equipment modification

Facilities will incur a one-time cost in 2023 to modify compressors, sampling connections, PRDs and OELs that were not designed and operated in a manner that minimizes releases into the environment. Most types of equipment components already meet this requirement. Assumptions about the percentages of equipment components that require modification and the associated costs are presented in Table 7.

Table 7: Assumptions for equipment modification
Equipment Component Type Percentage of Equipment Components Requiring Modification Additional Parts Needed Equipment Modification Cost Per Equipment Component — Capital, Labour, Overhead ($)
Compressors 30% Mechanical seal system with a barrier fluid system, or a closed-vent system 37,894.36
Sampling Connections 50% One 6 metre pipe and 3 ball valves 3,739.48
PRDs 30% One rupture disk, gate valve, tee, elbow, rupture disk holder, pressure gauge, bleed valve and steel body/trim 29,072.26
OELs 10% One 2.5 cm gate valve 340.69

Source: RTI Memo and stakeholder feedback

The total incremental cost for modifying equipment components (excluding their maintenance costs) is estimated to be $32.6M. Refineries will carry about $24.0M, upgraders $7.3M and petrochemical facilities $1.3M.

Inspection

Inspection costs include the cost of adding equipment components to facility inventories, the costs of performing three inspections per year using an OGI camera, and the costs of using a sniffer to quantify leaks when they are detected.

Many of the components that would be subject to the Regulations are assumed to already be included in inventories due to LDAR programs that occur in the baseline scenario. Incremental costs will be incurred to add components to inventories that are subject to the Regulations, but which are not subject to the baseline LDAR programs.

For many facilities, the inspection frequency will increase from once per year to three times per year, resulting in increased inspection costs. These costs are calculated based on the estimated time it takes to inspect each component with an OGI camera, multiplied by the labour cost per hour for the LDAR technician, multiplied by the total number of components at each facility.

When an OGI camera indicates that an equipment component is leaking, the LDAR technician must then use a sniffer to quantify the leak to determine if it is above the significant leak threshold. These costs are calculated based on the estimated time it takes to perform an inspection of a component with a sniffer, multiplied by the labour cost per hour for the LDAR technician, multiplied by the number of leaking components at each facility.

The incremental inspection costs are estimated to be $13.1M in total. Refineries will carry $9.8M, upgraders $3.1M and petrochemical facilities $0.2M.

Leak repair

The CBA model assumes that significant leaks are repaired immediately after detection. On average, about 55 000 more significant leaks are expected to be detected annually in the regulatory scenario over the BAU scenario. Most leaks can be repaired quickly and without replacing equipment components (e.g. by tightening the packing gland of a valve). In these cases, for each type of equipment component, repair costs are estimated as the product of the number of significant leaks, the time required to repair an equipment component of that type, and the wage rates of technicians, at $36 per hour.footnote 28 However, it is assumed that leaking pumps will be repaired by replacing the pump seals and that the cost of purchasing a replacement pump seal will be $390 per leaking pump.

The repair time depends on the type of equipment component. Some repairs can be completed while a process unit remains online, but others may require the unit to go offline. Table 8 lists the assumptions for repair hours by the type of equipment component.

Table 8: Assumptions for repair times
Equipment Component Type Percent Repaired Online Hours Required for Online Repair Percent Repaired Offline Hours Required for Offline Repair
Pumps 100% 16.00 0% 0.00
Valves 50% 0.17 50% 4.00
Connectors 75% 0.17 25% 2.00
Compressors 0% 0.00 100% 16.00
PRDs / OELs / Sampling connections 75% 0.17 25% 4.00

Source: RTI Memo and stakeholder feedback

A follow-up inspection of repaired leaks using a sniffer to verify that the equipment component is no longer leaking above the significant leak threshold is also required by the Regulations (for gas or vapour and light-liquid equipment components). This follow-up inspection must be conducted within the required repair timeline (usually 15 days after the detection of the leak). While this verification will be conducted under both the BAU and regulatory scenarios, facilities will incur additional repair verification costs as a result of more frequent repairs required by the Regulations.

The incremental repair costs are estimated to be $174.1M in total. Refineries will carry $121.0M, upgraders $49.5M and petrochemical facilities $3.6M.

Maintenance

Certain types of equipment components will require regular maintenance to ensure continued compliance with the Regulations. Equipment components subject to preventive requirements will need additional maintenance to ensure that the additional parts or systems function properly. These costs are calculated by obtaining a product of estimated per unit equipment maintenance costs (labour and capital) and the number of equipment components.

The incremental costs for maintenance are estimated to be $6.9M in total. Refineries will carry $4.7M, upgraders $2.1M and petrochemical facilities $0.1M.

Fenceline monitoring

The Regulations will require fenceline sampling locations, established in accordance with the requirements in U.S. EPA Methods 325A, at the property boundary of a facility or at an internal monitoring perimeter. This will result in a one-time cost of $60,000 for all facilities for planning and installing fenceline monitoring stations (i.e. site selection, technician training and the purchase and installation of sampling equipment). Facilities will also incur annual data collection and analysis costs of $0.9M.footnote 29 These costs are estimated based on the standard fenceline program, rather than a modified or alternative program.

The incremental costs of fenceline monitoring are estimated to be $11.8M in total. Refineries will incur $7.5M, upgraders $3.6M and petrochemical facilities $0.7M.

Administrative costs

The Regulations will result in an increase in administrative costs for affected facilities. Regulatees will need to become familiar with the administrative requirements and to keep records regarding LDAR activities and fenceline monitoring data. Facilities will also need to submit reports to the Department annually and assist auditors with the audits. The incremental administrative costs are estimated to be $2.2M. Refineries will carry $1.5M, upgraders $0.5M and petrochemical facilities $0.2M.

Other compliance costs

Facilities will need to review their equipment component inventory when the Regulations come into effect. Employee time will be spent on contracting and managing LDAR technicians and auditors. For facilities that do not use OGI cameras in the baseline scenario, one-time training costs would be incurred. Ongoing OGI camera maintenance costs would be required for issues like camera lens replacement, and there would be a small cost to each facility associated with video storage. These costs are estimated to be $2.6M in total. Refineries will carry $1.7M, upgraders $0.8M and petrochemical facilities $0.1M.

Costs to government

The Regulations will result in compliance promotion and enforcement costs for the federal government. The total government costs are estimated at $1.6M.

Compliance promotion

Compliance promotion activities include developing, posting and distributing promotional materials such as frequently asked questions and factsheets, holding information sessions, responding to information or clarification requests, tracking inquiries, sending reminder letters, advertising in trade and association magazines and attending trade association conferences. These activities will be intended to encourage the regulated community to achieve compliance with the Regulations. As the subject community is comprised only of large enterprises, compliance promotion activities will be minimal as those enterprises have the resources and capacity to develop a good understanding of their legal obligations on their own.

The total compliance promotion cost for the years 2021 to 2037 is expected to be approximately $92,000.

Enforcement

The federal government will also incur costs related to training, inspections, investigations and measures to deal with any alleged violations.

A one-time amount of $0.3 million will be required for the training of enforcement officers and $65,000 for strategic intelligence assessment work.

The annual enforcement costs are estimated to be about $84,000 broken down as follows: roughly $33,000 for inspections (which includes operations and maintenance costs, transportation and sampling costs) and measures to deal with alleged violations (including warnings, environmental protection compliance orders and injunctions); about $33,000 for analysis, administration and coordination to support enforcement activities; about $12,000 for ongoing intelligence; about $6,000 for investigations; and about $1,000 for prosecutions.

Cost-benefit statement

The results of the CBA are summarized in Table 9. The net present value of the Regulations is estimated to be about $1.5M. The benefits are estimated to be around $249.8M, while the costs are estimated to be around $248.3M. The largest quantified benefit (nearly $192M) corresponds to the human health gains from reducing VOC releases. The largest quantified cost (about $191M) is for the implementation of the LDAR program set out in the Regulations. The benefit from reducing exposure to carcinogenic VOCs cannot be quantified due to a lack of data. However, it is expected to reduce risk to human health.

Table 9: Cost-benefit statement — 2021–2037 ($M, PV)
2017 Canadian dollars, discounted to 2018, 3% discount rate. Numbers may not add up due to rounding.
Incremental Benefits and Costs 2021–2022 2023–2027 2028–2032 2033–2037 Total 2021–2037 Annualized
Quantified impacts
Benefits to Canadians
Health 10.3 68.7 60.8 51.6 191.4 14.5
Climate change table e3 note * 0.3 1.9 2.0 1.9 6.1 0.5
Environmental 0.2 1.2 1.0 0.9 3.3 0.2
Subtotal 10.7 71.7 63.8 54.5 200.8 15.3
Benefits to Industry
Recovered products 2.4 16.9 15.9 13.8 49.0 3.7
Total benefits 13.1 88.6 79.7 68.3 249.8 19.0
Costs to Industry
LDAR table e3 note ** 12.6 44.1 71.8 62.0 190.6 14.5
Equipment modification and maintenance 0.4 34.3 2.6 2.3 39.5 3.0
Fenceline monitoring 1.8 3.8 3.3 2.9 11.8 0.9
Other compliance costs 0.0 0.8 1.2 0.6 2.6 0.2
Administrative 0.1 0.8 0.7 0.6 2.2 0.2
Subtotal 14.9 83.8 79.7 68.3 246.7 18.7
Costs to Government
Enforcement and compliance promotion 0.6 0.4 0.3 0.3 1.6 0.1
Total costs 15.5 84.2 80.0 68.5 248.3 18.9
Net benefits 1.5 0.1        
Emission Reductions (kt)
VOCs 4 28 29 29 90 5.3
GHGs (CO2e) from methane reduction 5 37 39 39 120 7.1
Qualified impacts

Health benefits from reduced releases of carcinogens (e.g. 1,3-butadiene, benzene and isoprene).

Improved forest ecosystems and reduced risks of illness within wildlife or livestock from the reduction in concentrations of ground-level O3 and PM.

Table e3 note(s)

Table e3 note *

Benefits from CO2e of GHG emission reduction.

Return to table e3 note * referrer

Table e3 note **

Including costs of OGI cameras, inspections and repairs.

Return to table e3 note ** referrer
Distributional analysis

The shares of costs and reductions in VOC releases by province and type of facility are provided in the table below:

Table 10: Shares of costs and VOC reductions by province and type of facility
Province/Type of Facility Share of Costs (%) Share of Reductions in VOC Releases
Province
Alberta 47% 44%
Ontario 13% 13%
Quebec 13% 10%
Saskatchewan 9% 15%
British Columbia 7% 5%
New Brunswick 8% 9%
Newfoundland and Labrador 4% 4%
Type of facility
Refineries 70% 69%
Upgraders 27% 29%
Petrochemical facilities 3% 2%

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

Among the provinces, the greatest share of the costs will be incurred by Alberta, followed by Ontario, Quebec, Saskatchewan, British Columbia, New Brunswick, and Newfoundland and Labrador, in that order. The greatest reductions in VOC releases will be in Alberta, followed by Saskatchewan, Ontario, Quebec, New Brunswick, British Columbia, and Newfoundland and Labrador, in that order.

Among the various types of facility, most costs will occur at refineries, followed by upgraders and petrochemical facilities. Likewise, the greatest share of reductions in VOC releases will be in refineries, followed by upgraders and petrochemical facilities.

Competitiveness analysis
Consumer impacts

The Regulations are expected to result in higher production costs for the Canadian petroleum sector, but the magnitude of cost increases are expected to be small relative to historical industry expenditures. The degree to which production cost increases may be passed on to consumers would depend on various factors, including distribution constraints, the balance between regional demand of petroleum products and local production capacity in those areas, and currency exchange rates. In regions where compliance costs are passed down, the increase in prices is expected to be low for affected consumers.

Petroleum refining

The Department’s financial modelling shows that compliance costs associated with the Regulations are small relative to other capital and operating costs; after-tax cash flow per litre of refined productfootnote 30 is not expected to decrease by more than 0.05 cents per litre at any refinery, with a production-weighted average impact in the sector of around 0.01 cents per litre estimated as an impact of less than 0.5% of after-tax profits. In addition, since the Canadian market for refined petroleum products is highly integrated with that of the U.S., the Regulations are not expected to adversely affect the competitive position of any affected refinery, as their competitors in the U.S. face similar requirements (see the "Control of fugitive VOC releases in the United States" section).

Upgrading

The Regulations are not expected to have a meaningful impact on the profitability of the upgrading sector. The additional cost per barrel of SCO due to the Regulations is expected to be below 3 cents per barrel for any given year between 2021 and 2037, and equivalent to 1.3 cents per barrel on average over the same period, which represents less than 0.1% of historical pre-tax profits for any affected upgrader, based on quarterly data from 2017 to the first quarter of 2019.

Petrochemical manufacturing

Competitiveness analysis of the petrochemical sector is complicated because these facilities produce and sell a wide range of petrochemical products to various markets. However, just like the petroleum and upgrading sectors, the Regulations are expected to have a minimal impact on the competitive position of the petrochemical sector, as the costs associated with the Regulations are low relative to other capital and operating costs.

Sensitivity analysis

A sensitivity analysis is conducted to examine the impact of risk and uncertainty on costs and benefits. The key variables considered are equipment component counts, the conversion factor between VOC release reductions and recovered liquid products, downstream combustion of recovered products, fuel price forecasts, the overhead rate on wages, and the discount rate.

Equipment component inventory

The average equipment component counts presented in the RTI Memo were applied to most facilities in this analysis. However, the actual equipment component counts at individual facilities can vary significantly from these average estimates. A sensitivity analysis was conducted on equipment component inventory and the results show that an increase (decrease) of 30% in equipment component inventory will lead to an increase (decrease) in the net present value of total costs of $68M and 30% in emission reductions.

Conversion factor between reduced VOC releases and recovered liquid products

The central analysis assumes that one tonne of reduction in VOC releases will result in 1 000 L of recovered liquid products. However, it is uncertain how many litres of liquid products will be recovered from each tonne of reduced VOC releases. A sensitivity analysis was conducted on the conversion factor and the results show that an increase (decrease) of 30% in conversion factor will lead to an increase (decrease) of $14.7M in the net present value of recovered products.

Downstream combustion of recovered products

An upper bound assessment of regulatory impacts would account for the combustion of recovered gasoline and other products that are exported and combusted elsewhere. Due to limited data, only GHG emissions from the combustion of recovered gasoline can be estimated. It is assumed that captured gasoline is incremental to gasoline which would otherwise be combusted. This incremental combustion would generate approximately 54 kt CO2e of GHG emissions in the worst-case scenario, where exported gasoline displaces some zero-emitting alternative energy source. Therefore, the net reduction of GHG emissions would be about 66 kt CO2e. This would result in a reduction of $2.2M in the net present value of benefits.

Overhead rate

As a conservative assumption, the CBA assumes that all facilities will use external consultants to conduct their LDAR programs. Based on the U.S. EPA’s CEMS Cost Model (2002), the central analysis uses a factor of three as an overhead premium on the wages of external staff. A sensitivity analysis was conducted to estimate the regulatory costs if the overhead factor was instead only 1.5; however, the assumption that all facilities use consultants was maintained. In this scenario, the net present value of costs would decrease by $86.6M, which would yield a net benefit of $88.2M.

Discount rate

In the central case for this analysis, the discount rate of 3% is used to calculate the PV of costs and benefits. Table 11 shows total benefits and total costs when there is no discounting (undiscounted values) and when the discount rate is 7%.

Table 11: Discount rate ($M)
  0% 3% 7%
Total benefits 350.2 249.8 165.8
Total costs 346.5 248.3 166.3
Net benefits 3.7 1.5 -0.5

Small business lens

No small businessesfootnote 31 will be affected by the Regulations. All facilities that will be subject to the Regulations are considered large businesses, with more than 100 employees or annual gross revenues exceeding $5M. The small business lens therefore does not apply to the Regulations.

One-for-one rule

The Regulations will be new regulations and will result in an increase in administrative burden costs for regulated parties. The Regulations are therefore considered an “IN” under the one-for-one rule. Following the Treasury Board of Canada Secretariat’s guidance,footnote 32 and using a 7% discount rate and 10-year time frame beginning in 2021, it is estimated that the Regulations will result in an increase in annualized administrative burden costs of $101,651 (in 2012 Canadian dollars) for all affected facilities for the years 2021 to 2030, or $4,066 per facility.footnote 33

One-time costs

Senior management at each facility will spend an average of one hour to become familiar with the administrative requirements of the Regulations in 2021. It is assumed that the average wage rate for this position is $45/hour based on guidance provided by the Treasury Board Secretariat (TBS).

A chemical engineer or an employee with training in natural or applied science at each facility will need an average of

The assumed average wage rate for chemical engineers is $36/hour, based on TBS guidance.

Ongoing costs

A chemical engineer or an employee with training in natural or applied science (with the same wage rate assumption as above) at each facility will need, on an annual basis, an average of

In addition, a chemical engineer or an employee with training in natural or applied science at each facility will need an average of 75 hours to assist auditors every four years for the years 2024 to 2037.

Regulatory cooperation and alignment

As described in the "Current LDAR programs" and "Leak dection and measurement" sections, fugitive VOC releases in Canada are currently managed under a patchwork of voluntary codes of practice, facility permits, municipal by-laws and provincial regulations. The Regulations will modernize the current Canadian regime and better align with current U.S. regulations. The U.S. EPA was consulted on various aspects of the Regulations, in the context of the Canada-U.S Workplan on Oil and Gas Emission under the Canada-U.S. Air Quality Agreement.footnote 34

The structure of the Regulations is similar to the U.S. EPA regulatory regime, with modifications to reflect Canadian conditions (including existing requirements in various Canadian jurisdictions) and input from stakeholders and partners. Some key areas are highlighted below. In addition to these harmonized requirements, the Department will also consider equivalency agreements and single-window reporting as appropriate.

Inspection frequency

The U.S. requires monthly or quarterly inspections for many equipment components, but Canadian jurisdictions generally require inspections three times per year (Ontario, Quebec) or annually (Metro Vancouver, CCME Code, CFA Code). Under the Regulations, equipment components will be inspected three times per year. This will avoid requiring inspections during winter, while still ensuring that equipment components are inspected regularly throughout the rest of the year.

Significant leak threshold

In the U.S., significant leak thresholds range from 500 ppmv to 10 000 ppmv. In Canada, leak thresholds from 1 000 ppmv (Metro Vancouver, Ontario, Quebec) to 10 000 ppmv (CCME Code, CFA Code) are used in various jurisdictions. Under the Regulations, the significant leak threshold for most equipment components will be 10 000 ppmv until December 31, 2026, and 1 000 ppmv thereafter. This approach recognizes the importance of controlling small and large leaks of PRGs, while also providing facilities with lead time to prepare for the 1 000 ppmv significant leak threshold through equipment upgrades and improved operational procedures.

Leak inspection technology

The U.S. and Ontario allow the use of OGI cameras for most inspections, but require that each equipment component be inspected using a sniffer once per year. Other Canadian jurisdictions generally refer to the CCME Code, which recommends the use of a sniffer but does not rule out other technologies (OGI technology was not widely used when the CCME Code was published in 1993). Under the Regulations, most inspections can be conducted using either a sniffer or an OGI camera. This approach recognizes the continuing development of OGI technology, which was highlighted in comments from industry and other stakeholders and partners. The faster pace of inspections using OGI cameras allows for a larger number of equipment components to be included in the LDAR program.

Fenceline monitoring

The U.S., Ontario and New Brunswick require refineries to conduct fenceline monitoring for benzene, using the methodology specified in U.S. EPA Methods 325A and 325B.footnote 35 Under the Regulations, the same EPA Methods will be used. In addition to benzene, the Regulations will require all affected facilities to monitor for 1,3-butadiene, toluene, ethylbenzene, m,p-xylene and o-xylene. These additional measurements will allow the Department to better evaluate the performance of the Regulations over time and to inform neighbouring communities about the concentrations of these toxic substances in the air. In order to reduce duplication with provincial fenceline monitoring programs, facilities can apply for a modified or alternative fenceline monitoring program based on their existing program.

Rationale

Volatile organic compounds are a precursor pollutant to the formation of ground-level O3 and PM, the main constituents of smog. Exposure to ground-level O3 and PM has harmful effects on human health, causing respiratory and cardiac symptoms, in some cases leading to premature mortality. Higher levels of ground-level O3 can also reduce crop productivity. Releases of VOCs from leaking equipment components in petroleum and petrochemical facilities include PRGs. These gas mixtures may contain carcinogenic components (e.g. 1,3-butadiene, benzene and isoprene) that pose risks to Canadians in the vicinity of these facilities.

An LDAR program is acknowledged as constituting the best practice for controlling fugitive VOC releases from these facilities. Most facilities have implemented LDAR programs based on the voluntary CCME Code, with the focus on reducing VOC releases from equipment components leaking at high concentrations. However, significant areas of improvement have been identified. Furthermore, even low concentrations of the carcinogens in PRGs can have harmful effects on human health.

The Regulations were developed to address these issues. Facility operators will conduct more frequent inspections on a broader range of equipment components and will repair equipment components leaking at lower VOC concentrations. Additionally, certain equipment components will need to be designed and operated in a manner that minimizes VOC releases. These actions will further reduce releases of VOCs, including PRGs. Facility operators will also be required to collect samples at sampling locations along the facility fenceline and to analyze the samples to determine the concentrations of certain VOCs.

As a result of the Regulations, VOC releases will be reduced by 90 kt and GHG emissions will be reduced by 120 kt CO2e for the years 2021 to 2037, which will result in improvements in human health and environmental quality, as well as benefits to businesses from recovered products. These benefits are valued at around $249.8M, while the total costs to the industries and the Government are estimated at around $248.3M. The costs to businesses are not expected to affect their competitiveness in the petroleum and petrochemical markets.

The Regulations are designed to harmonize, where possible, with the regulatory requirements of other jurisdictions, including provinces and the U.S. The Regulations will also adopt a single-window reporting approach where possible, to minimize administrative burden on facilities. In addition, the Regulations will provide regulatory certainty to the industry and other stakeholders, which will create a level playing field and encourage them to plan and invest into the future with confidence.

Strategic environmental assessment

A strategic environmental assessment (SEA) of the CMP was completed.footnote 36 The SEA concluded that activities under the CMP will support the Federal Sustainable Development Strategy (FSDS) goal to minimize the threat to air quality so that the air Canadians breathe is clean and supports healthy ecosystems.

Gender-based analysis plus

No gender-based analysis plus (GBA+) impacts have been identified for these Regulations.

Implementation, compliance and enforcement, and service standards

Compliance promotion

Compliance promotion activities are intended to encourage the regulated community, composed solely of large enterprises, to achieve compliance. Immediately after publication of the Regulations, and with the coming into force of new requirements in subsequent years, compliance promotion activities could include

Once all of the requirements are in force, compliance promotion activities will possibly be kept at a maintenance level and be limited to responding to and tracking inquiries. Additional compliance promotion may be required if, following an assessment of the promotional activities, compliance with the Regulations is found to be low.

Enforcement

The Regulations are made under CEPA, so enforcement officers will, when verifying compliance with the Regulations, once they are in force, apply the Compliance and Enforcement Policy for CEPA.footnote 37 That Policy sets out the range of possible responses to alleged violations, including warnings, directions, environmental protection compliance orders, tickets, ministerial orders, injunctions, prosecution and environmental protection alternative measures (which are an alternative to a court prosecution after the laying of charges for a CEPA violation). In addition, the Policy explains when the Department will resort to civil suits by the Crown for cost recovery.

To verify compliance, enforcement officers may carry out an inspection. An inspection may identify an alleged violation, and alleged violations may also be identified by the Department’s technical personnel, or through complaints received from the public. Whenever a possible violation of any regulations is identified, enforcement officers may carry out investigations.

If, following an inspection or an investigation, an enforcement officer discovers an alleged violation, the officer will choose the appropriate enforcement action based on the following factors:

The Regulations also require related changes to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999). Those Regulations designate the various regulatory provisions in various CEPA regulations that are subject to an increased fine regime following a successful prosecution of an offense involving harm or risk of harm to the environment, or obstruction of authority.

Service standards

The Department, in its administration of the Regulations, will respond to submissions and inquiries from the regulated community in a timely manner taking into account the complexity and completeness of the request.

In addition, the Department intends to develop information sheets and/or a technical guidance document describing the required information and format to be followed when submitting a plan or report.

Performance measurement and evaluation

The expected outcomes of the Regulations are related to domestic priorities to reduce fugitive releases of VOCs, including PRGs, from petroleum refineries and upgraders, and from petrochemical facilities that are operated in an integrated way with those facilities. The performance of the Regulations in achieving these outcomes will be measured and evaluated.

Clear and quantified performance indicators will be defined for each outcome. These indicators include facility registration, compliance with the regulatory requirements, repair or replacement of leaking equipment components and reported emission data (including calculated emissions from leaking equipment components, as well as fenceline monitoring results). Achievement of the performance indicators will be tracked through annual or on-demand reporting requirements, as well as through enforcement activities.

Regular review and evaluation of these performance indicators will allow the Department to determine the impacts of the Regulations on the affected facilities and to evaluate the performance of the Regulations in reaching the intended targets.

Contacts

Magda Little
Director
Oil, Gas and Alternative Energy Division
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: ec.covsecteurpetrolier-vocpetroleumsector.ec@canada.ca

Matt Watkinson
Director
Regulatory Analysis and Valuation Division
Environment and Climate Change Canada
200 Sacré-Cœur Boulevard
Gatineau, Quebec
K1A 0H3
Email: ec.darv-ravd.ec@canada.ca