EXTRA Vol. 152, No. 1

Canada Gazette

Part Ⅱ

OTTAWA, THURSDAY, APRIL 26, 2018

Registration

SOR/2018-66 April 4, 2018

CANADIAN ENVIRONMENTAL PROTECTION ACT, 1999

P.C. 2018-396 April 3, 2018

Whereas, pursuant to subsection 332(1)footnotea of the Canadian Environmental Protection Act, 1999 footnoteb, the Minister of the Environment published in the Canada Gazette, Part I, on May 27, 2017, a copy of the proposed Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector), substantially in the annexed form, and persons were given an opportunity to file comments with respect to the proposed Regulations or to file a notice of objection requesting that a board of review be established and stating the reasons for the objection;

Whereas, pursuant to subsection 93(3) of that Act, the National Advisory Committee has been given an opportunity to provide its advice under section 6footnotec of that Act;

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

Therefore, Her Excellency the Governor General in Council, on the recommendation of the Minister of the Environment and the Minister of Health, pursuant to subsection 93(1), section 286.1footnoted and subsection 330(3.2)footnotee of the Canadian Environmental Protection Act, 1999 footnoteb, makes the annexed Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector).

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

Purpose and Overview

Protection of environment and reduction of harmful effects

1 For the purpose of protecting the environment on which life depends and of reducing the immediate or long-term harmful effects of the emission of methane and certain volatile organic compounds on the environment or its biological diversity, these Regulations

Interpretation

Definitions

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

Interpretation of documents incorporated by reference

(2) For the purpose of interpreting any document that is incorporated by reference into these Regulations, “should” must be read to mean “must” and any recommendation or suggestion must be read as an obligation, unless the context requires otherwise. For greater certainty, the context of the accuracy or repeatability of a measurement can never require otherwise.

Inconsistency

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

Documents incorporated by reference

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

Responsibility

Operator

3 An operator for an upstream oil and gas facility must ensure that a requirement set out in these Regulations in respect of the facility or equipment at the facility — along with any related requirement in respect of recording information, keeping documents and providing reports — is complied with.

PART 1

Onshore Upstream Oil and Gas Facilities

Application

Onshore facilities

4 This Part applies in respect of upstream oil and gas facilities other than those located offshore.

General Requirements

Hydrocarbon Gas Conservation and Destruction Equipment
Hydrocarbon gas conservation equipment

5 (1) Hydrocarbon gas conservation equipment that is used at an upstream oil and gas facility must

Exception to paragraph (1)(c)

(2) Despite paragraph (1)(c), no recommendation referred to in that paragraph need be treated as a requirement and complied with if the operator for a facility has a record that establishes that without that compliance the hydrocarbon gas conservation equipment’s ability to respect paragraph (1)(a) is unaffected.

Records — conservation equipment

6 A record in respect of any hydrocarbon gas conservation equipment used at an upstream oil and gas facility must be made that indicates

Conserved gas — use

7 Hydrocarbon gas that has been captured and conserved in hydrocarbon gas conservation equipment must be conserved until it is

Records — conserved gas used as fuel

8 A record in respect of any hydrocarbon gas that is combusted as fuel in a combustion device referred to in paragraph 7(a) must be made that indicates for each month during which the device is used, the percentage, at any given moment, of the combusted hydrocarbon gas that is released as hydrocarbon gas, with supporting documents, based on

Hydrocarbon gas destruction equipment

9 Hydrocarbon gas destruction equipment that is used at an upstream oil and gas facility must satisfy the requirements related to the destruction of hydrocarbon gas set out in

Records — hydrocarbon gas destruction equipment

10 A record in respect of any hydrocarbon gas destruction equipment used at an upstream oil and gas facility must be made that demonstrates, with supporting documents, that the requirements related to the destruction of hydrocarbon gas set out in the applicable document referred to in section 9 are satisfied.

Well Completion involving Hydraulic Fracturing
Application

11 (1) This section applies in respect of an upstream oil and gas facility that includes a well that undergoes hydraulic fracturing and whose production has a gas-to-oil ratio of at least 53:1, based on the most recent determination of the gas-to-oil ratio prior to the hydraulic fracturing.

No venting

(2) Hydrocarbon gas associated with flowback at a well at an upstream oil and gas facility must not be vented during flowback but must instead be captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.

Exception

(3) Subsection (2) does not apply if all the gas associated with flowback at the well does not have sufficient heating value to sustain combustion.

Records — hydraulic fracturing

12 A record in respect of each well at an upstream oil and gas facility that undergoes hydraulic fracturing must be made

Non-application — British Columbia and Alberta

13 Sections 11 and 12 do not apply in respect of an upstream oil and gas facility that is located in

Compressors
Capture or venting of emissions

14 The emissions of hydrocarbon gas from the seals of a centrifugal compressor, or from the rod packings and distance pieces of a reciprocating compressor, that has a rated brake power of 75 kW or more at an upstream oil and gas facility must be

Measurement of flow rate

15 The flow rate of emissions of hydrocarbon gas released from the vents referred to in paragraph 14(b) of a compressor must be measured by means of

Flow meters

16 (1) The flow meter must be calibrated in accordance with the manufacturer’s recommendations such that its measurements have a maximum margin of error of ±10%.

Measurements by flow meters

(2) Those measurements must be made

Initial and subsequent measurements

(3) The flow rate must be measured within the following periods:

Measurements — maximum or average

(4) The initial and each subsequent measurement of the flow rate must be based on measurements made by the flow meter over a continuous period of at least five minutes and is

Extension — not operating or not pressurized

(5) Despite subsection (3), if no measurement has been made by the last day of a period referred to in that subsection — but, on that day, the compressor is not operating, in the case of a centrifugal compressor, or the compressor is not pressurized, in the case of a reciprocating compressor — the measurement must be made under that subsection on or before the 30th day after the day on which the compressor is next operating or pressurized, as the case may be.

Extension — pressurized for < 1,314 hours per 3 years

(6) Despite subsection (3), a period referred to in that subsection is extended by 365 days if the operator for the facility makes a record that demonstrates that, during the three calendar years immediately before the end of the period, the compressor was pressurized for less than 1,314 hours, as determined by an hour meter or as recorded in a log of operations.

Continuous monitoring devices

17 A continuous monitoring device must

Corrective action

18 (1) If the flow rate of emissions of hydrocarbon gas released from vents referred to in paragraph 14(b) of a compressor, measured in accordance with subsection 16(2), is greater than the applicable flow rate limit set out in subsection (2) or (3) or if the alarm referred to in paragraph 17(c) is triggered, corrective action must be taken to reduce that flow rate to below or equal to that limit, as demonstrated by a remeasurement that results,

Flow rate limit — centrifugal compressors

(2) For emissions that are from the seals of a centrifugal compressor, the flow rate limit is

Flow rate limit — reciprocating compressors

(3) For emissions that are from the rod packings and distance pieces of a reciprocating compressor, the flow rate limit is

Remeasurement

(4) The remeasurement referred to in paragraph (1)(a) or (b) must be taken in accordance with section 15 on or before the later of

Estimated volume

(5) The estimated volume of hydrocarbon gas must be based on the most recent flow rate of emissions of hydrocarbon gas released from vents referred to in paragraph 14(b) of the compressor, as determined by a flow meter or a continuous monitoring system in accordance with section 15.

Records — compressors and vents

19 (1) A record must be made that indicates for each compressor referred to in section 14

Records — flow meters

(2) A record must be made that indicates, for each measurement, including a remeasurement, the flow rate of emissions from a vent referred to in paragraph 14(b) made by means of a flow meter referred to in paragraph 15(a),

Records — continuous monitoring devices

(3) A record must be made that indicates, for each measurement, including a remeasurement, of the flow rate of emissions from a vent referred to in paragraph 14(b) made by means of a continuous monitoring device referred to in paragraph 15(b),

Records — corrective actions taken

(4) A record must be made that indicates, for each corrective action taken,

Conditional Requirements

Conditions
Application of sections 26 to 45

20 (1) Sections 26 to 45 apply in respect of an upstream oil and gas facility as of the first day of the month that begins after the facility produces or receives — or is expected to produce or receive — a combined volume of more than 60 000 standard m3 of hydrocarbon gas for a period of 12 months, determined as follows:

Well completion

(2) For the purpose of subsection (1), if a well at the facility undergoes well completion during a given month, the portion of the combined volume referred to in that subsection that corresponds to the production of hydrocarbon gas from the well must be based on the volume of hydrocarbon gas expected to be produced by the well for the 12-month period after the given month, as determined in accordance with the applicable method set out in section 23.

Records — non-application

21 If none of sections 26 to 45 apply, for a given month, in respect of an upstream oil and gas facility, a record, with supporting documents, must be made that indicates

Records — application

22 A record must be made that indicates the following information for the first month that begins after the facility produces or receives — or is expected to produce or receive — a combined volume of more than 60 000 standard m3 of hydrocarbon gas for a period of 12 months as determined in accordance with subsection 20(1):

Determination of Volume of Gas
Applicable methods

23 (1) For the purpose of sections 20 and 26, the volume of hydrocarbon gas produced, received, vented or destroyed at, or delivered from, an upstream oil and gas facility must be determined in accordance with the applicable method set out in

Directive PNG017 and AER 017

(2) Despite paragraphs (1)(b) and (c), for the purpose of sections 12.2.2.1 and 12.2.2.2 of the Saskatchewan Directive PNG017 and of the AER Directive 017, the gas production per well per day is to be determined

−0.5Pw + 150

Determination of gas-to-oil ratio

24 (1) The determination of a gas-to-oil ratio for the purpose of clause 23(2)(b)(ii)(A) is made using the formula

G/O

Determination of value of G

(2) The measurements to determine the value of G must be taken over a continuous period of at least 72 hours with a continuous measuring device or using a flow meter with at least one reading taken every 20 minutes.

Exception

(3) Despite subsection (2), the measurements to determine the value of G may be taken over a continuous period of at least 24 hours, if

Determination of the value of O

(4) The measurements to determine the value of O must be taken after the water has been separated from the liquid produced from the well and taken

Steady state

(5) A measurement taken under any of subsections (2) to (4) must be taken while the well is operating in a steady state, that is, it must be taken only if no adjustment that could result in a change to the oil or gas production rates has been made to the production parameters for at least 48 hours before the measurement is taken.

Measuring equipment — directives

(6) The continuous measuring device or flow meter used to determine the gas-to-oil ratio must meet the requirements of section 2 of the Saskatchewan Directive PNG017 or section 2 of the AER Directive 017.

Frequency of determination

(7) A determination of the gas-to-oil ratio must be made

Records

25 A record must be made that indicates

Venting Limit
15 000 standard m3 per year

26 (1) An upstream oil and gas facility must not vent more than 15 000 standard m3 of hydrocarbon gas during a year.

Excluded volumes

(2) The volumes of hydrocarbon gas vented that arose from the following activities are excluded from the determination of the volume vented for the purpose of subsection (1):

Non-application of subsection (1)

(3) Subsection (1) does not apply in respect of a facility, as of a given month, if the combined volume of hydrocarbon gas that was vented or destroyed at, or delivered from, the facility was less than 40 000 standard m3 for the 12 consecutive months before that given month.

Re-application of subsection (1)

(4) Despite subsection (3), subsection (1) does apply in respect of a facility referred to in subsection (3), as of a subsequent month, if the combined volume of hydrocarbon gas that was vented or destroyed at, or delivered from, the facility was equal to or greater than 40 000 standard m3 for the 12 consecutive months before that subsequent month.

Records — volumes of hydrocarbon gas

27 For each month that an upstream oil and gas facility operates, a record, with supporting documents, must be made that indicates

Leak Detection and Repair Program
Establishment of Program

Non-application to certain equipment components

28 (1) Sections 29 to 36 do not apply in respect of

Record

(2) A record must be made that indicates whether an equipment component is an equipment component referred to in any of paragraphs (1)(a) to (c).

Regulatory or alternative LDAR programs

29 (1) An operator for a facility must — in order to limit fugitive emissions containing hydrocarbon gas from equipment components at the facility — establish and carry out at the facility

Notice to Minister

(2) An operator for a facility that establishes a leak detection and repair program referred to in paragraph (1)(b) must, without delay, notify the Minister to that effect.

Regulatory LDAR Programs

Obligation to inspect

30 (1) An equipment component at an upstream oil and gas facility must be inspected, during the periods referred to in subsection (3), for the release of hydrocarbons by means of an eligible leak detection instrument.

Eligible leak detection instruments

(2) The following leak detection instruments are eligible:

Period for inspections

(3) The period for inspections is as follows:

Operation and maintenance

(4) An eligible leak detection instrument must be operated and maintained in accordance with the recommendations, if any, of its manufacturer.

Training

(5) The inspection must be conducted by an individual who, not more than five years before the inspection, has received training in

Leaks

31 (1) A release of hydrocarbons from an equipment component is a leak if

Release not considered a leak

(2) A release that is detected under paragraph (1)(b) is no longer considered to be a leak if the equipment component undergoes an inspection conducted by means of an eligible portable monitoring instrument in accordance with EPA Method 21 and the release is determined to consist of less than 500 ppmv of hydrocarbons.

Period for repair

32 (1) A leak from an equipment component that is detected, whether as a result of an inspection or otherwise, must be repaired

Next planned shutdown

(2) The next planned shutdown must be scheduled not later than the date on which the estimated volume of hydrocarbon gas, expressed in standard m3, that, beginning from the day on which the leak is detected, would if no repairs are made be emitted from the leaking equipment component in question and from all other equipment components that are also leaking as of that day is equal to the volume of hydrocarbon gas, expressed in standard m3, that would be emitted due to purging of hydrocarbon gas from equipment components in order to carry out the repair.

Repair

(3) A leak in an equipment component is considered to be repaired if the release is determined to consist of less than 500 ppmv of hydrocarbons based on an inspection of the equipment component by means of an eligible portable monitoring instrument in accordance with EPA Method 21 that is capable of measuring hydrocarbon concentrations in ppmv.

Extension up to six months for repair

33 (1) An operator for an upstream oil and gas facility that must repair an equipment component on or before the end of a period referred to in paragraph 32(1)(b) may, not later than 45 days before the end of the period, apply to the Minister to extend the period for up to six months.

Granting of extension

(2) The Minister must grant the application and extend the period for up to six months if the application contains the information set out in Schedule 1 and

Renewal

(3) The period granted under subsection (2) may be further extended by application made under subsection (1). At most two applications for a further extension may be made.

Refusal of application

(4) The Minister must refuse the application if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in the application.

Revocation of extension

34 (1) The Minister must revoke the extension granted under subsection 33(2) if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in their application for the extension.

Conditions for revocation

(2) The Minister must not revoke the extension unless the Minister has provided the applicant with

Alternative LDAR Programs

Requirements for alternative program

35 (1) The alternative leak detection and repair program must include measures respecting

Reversion to regulatory program

(2) An operator for a facility that has not made a demonstration required by paragraph 29(1)(b) must establish and carry out a regulatory leak detection and repair program.

Records

Regulatory LDAR programs

36 (1) A record, with supporting documents, must be made of the following information related to the carrying out of a regulatory leak detection and repair program:

Alternative LDAR programs

(2) A record, with supporting documents, must be made of the following information related to the carrying out of an alternative leak detection and repair program:

Document-keeping

(3) A copy of each recommendation of the manufacturer for the operation and maintenance, if any, of each eligible leak detection instrument that is used must be kept.

Pneumatic Controllers and Pneumatic Pumps
Pneumatic controllers — bleed rate

37 (1) A pneumatic controller at an upstream oil and gas facility must not operate using hydrocarbon gas, other than propane, unless

Exception — control of production processes

(2) Despite paragraph (1)(a), a pneumatic controller at an upstream oil and gas facility may operate using hydrocarbon gas, other than propane, at an operational setting such that its bleed rate for that operational setting is more than 0.17 standard m3/h if the operator for the facility has a written record, with supporting documents, that demonstrates that the pneumatic controller must operate at that operational setting because of the need for the pneumatic controller to have a sufficient response time to control a process in the facility’s production activities.

Records — pneumatic controllers

38 A record in respect of each pneumatic controller used at an upstream oil and gas facility that operates using hydrocarbon gas must be made that indicates

Pneumatic pumps

39 (1) Unless an operator for an upstream oil and gas facility has a permit issued in accordance with subsection 40(2), a pneumatic pump or a group of pneumatic pumps, used at the facility that pumps methanol into a common stream or an equipment component — must not operate using hydrocarbon gas if the pump or the group of pumps has, in a month, pumped more than 20 L of methanol per day on average over the month.

Demonstration of quantity of liquid pumped

(2) An operator for the facility must, for each pump or group of pumps referred to in subsection (1) that operates during a month at the facility, demonstrate the quantity of liquids that it pumped, on average, per day over the month by means of

When subsection (2) no longer applies

(3) Subsection (2) no longer applies in respect of a pump or group of pumps as of the end of a month during which it operated at the facility and records establish that it pumped, or could have pumped, more than 20 L of liquid per day on average over the month.

Non-application of subsections (1) and (2)

(4) Subsections (1) and (2) do not apply in respect of any pneumatic pump if hydrocarbon emissions from it are captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.

Permit — pneumatic pumps

40 (1) An operator for an upstream oil and gas facility may, on or before June 30, 2022, apply to the Minister for a permit to have a pneumatic pump at the facility operate using hydrocarbon gas while its hydrocarbon emissions are not captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.

Issuance of permit

(2) The Minister must issue the permit if the application contains the information set out in Schedule 2 and documents that establish that

Duration

(3) A permit takes effect on January 1, 2023 and expires on the earliest of

Refusal of application

(4) The Minister must refuse the application if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in the application.

Tagging

41 (1) A pneumatic controller that is referred to in subsection 37(2) or a pneumatic pump referred to in a permit issued under subsection 40(2) must be tagged to indicate that it is not subject to subsection 37(1) or 39(1) or an entry to that effect must be made in an electronic tracking system.

Identifier

(2) The tag or the entry must also include an identifier for the pneumatic controller or the pneumatic pump.

Other Equipment
Pipes and hatches

42 A hatch and the open end of a pipe at an upstream oil and gas facility must be closed — other than during an operation at the facility that requires the hatch or pipe to be open — in such a way as to minimize the emission of hydrocarbon gas.

Sampling systems and pressure relief devices

43 A sampling system or a pressure relief device used at an upstream oil and gas facility must be installed and operated in such a way as to minimize the emission of hydrocarbon gas from the system or the pressure relief device.

Records — hatches, pipes, systems and devices

44 A record must be made that indicates whether an upstream oil and gas facility has a hatch, a pipe with an open end or uses a sampling system or pressure relief device.

Revocation of Permit
Subsection 40(2)

45 (1) The Minister must revoke a permit issued under subsection 40(2) if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in their application for the permit.

Conditions for revocation

(2) The Minister must not revoke a permit unless the Minister has provided the applicant with

PART 2

Offshore Upstream Oil and Gas Facilities

Application

Offshore facilities

46 (1) This Part applies in respect of upstream oil and gas facilities located offshore.

Non-application

(2) Despite subsection (1), this Part does not apply in respect of an offshore facility if

Venting Limit

15 000 standard m3 per year

47 (1) An offshore facility must not vent more than 15 000 standard m3 of hydrocarbon gas during a year.

Excluded volume — health or safety

(2) Any volume of hydrocarbon gas that is vented from the offshore facility in order to avoid serious risk to human health or safety arising from an emergency situation is excluded from the determination of the volume vented for the purpose of subsection (1).

Records — annual volume vented

48 (1) For each year that an offshore facility operates, a record, with supporting documents, must be made that indicates the volume of hydrocarbon gas that was vented, expressed in standard m3.

Records — emergency situation

(2) For each volume of vented hydrocarbon gas arising from an emergency situation referred to in subsection 47(2), a record must be made that indicates:

Compressors

Capture or venting of emissions

49 The emissions of hydrocarbon gas from the seals of a centrifugal compressor at an offshore facility must be

Continuous monitoring devices

50 (1) The flow rate of emissions of hydrocarbon gas from vents referred to in paragraph 49(b) must be measured by means of a continuous monitoring device.

Requirements

(2) A continuous monitoring device must

Flow rate limit

(3) The flow rate limit of emissions of hydrocarbon gas from the vents of a compressor is

Corrective action

(4) If the alarm is triggered, corrective action must be taken to reduce the flow rate to below or equal to the applicable flow rate limit, as demonstrated by the absence of an alarm when the compressor begins to operate following the taking of that action.

Records

51 A record must be made that indicates the following information concerning centrifugal compressors:

Gas Detection System and Repair of Leaks

Requirements

52 (1) An offshore facility must be equipped with a gas detection system that satisfies the requirements of section 32 of the Newfoundland Offshore Petroleum Installations Regulations and section 32 of the Nova Scotia Offshore Petroleum Installations Regulations.

Repair

(2) A leak must be repaired within 730 days after the day on which it is detected by the gas detection system or is detected by means of an auditory method, an olfactory method or a visual method, including the observation of the dripping of hydrocarbon liquids from the equipment component.

Records

53 A record must be made that indicates the following information concerning the detection and repair of leaks:

PART 3

Administration

Registration

Registration report

54 (1) An upstream oil and gas facility in respect of which any of sections 5, 9, 11, 14 and 15 apply or in respect of which sections 26 to 45 apply and an offshore facility in respect of which section 46 applies must be registered by providing the Minister with a registration report for the facility that contains the information set out in Schedule 3.

Date of registration

(2) The facility must be registered not later than 120 days after the later of

Updated information

(3) If there is a change such that the information provided in the facility’s registration report is no longer accurate, a notice to that effect that contains the updated information, along with the information referred to in item 4 of Schedule 3, must be sent to the Minister not later than 90 days after the change.

Provision of information

55 (1) Information that is required under section 54 to be in a registration report provided to the Minister may be provided to the Minister via an approved entity.

Deemed provision of registration report

(2) If all of the information required to be in a registration report is provided to the Minister via an approved entity, the operator for that facility must notify the Minister to that effect. The registration report is deemed to have been provided to the Minister on the day on which the Minister receives that notice.

Approval of entity

(3) The Minister may approve an entity for the purpose of subsection (1) if the Minister concludes an arrangement with the entity under which information referred to in section 54 that is provided to the entity is accessible to the Minister.

Publication of approved entities

(4) The Minister must publish a list of approved entities in the Environmental Registry established under section 12 of the Canadian Environmental Protection Act, 1999.

Withdrawal of approval

(5) The Minister may withdraw the approval of an entity and publish a notice to that effect in the Environmental Registry.

Record-making and Updating and Keeping of Documents

Record-making and updates

56 (1) A record that is required to be made under these Regulations must be made within 30 days after the day on which the information to be recorded becomes available. The record must be updated within 30 days after the information to be updated becomes available.

Record-keeping — indefinite

(2) A record, along with supporting documents, of information that applies on an ongoing basis must be kept indefinitely until an update is required.

Record-keeping — five years

(3) If an update referred to in subsection (2) is required, the record of the information, along with its supporting documents, as recorded before the updating must be kept for five years after the updating.

Record-keeping — five years

(4) A record, along with supporting documents, of information that applies only in respect of a given day, must be kept for five years after that given day.

Document-keeping

(5) A document that is required to be kept under these Regulations must be kept for five years.

Place kept

(6) The records and documents must be kept at the upstream oil and gas facility to which they relate or at another place in Canada where they can be inspected.

Provision of records

(7) On the Minister’s request, the operator must, within 60 days after the day on which the request was made, provide any of the records or documents kept to the Minister.

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

57 The schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) footnote1 is amended by adding the following in numerical order:

Item

Column 1

Regulations

Column 2

Provisions

30

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

(a) subsection 5(1)

(b) section 6

(c) section 7

(d) section 8

(e) section 9

(f) section 10

(g) subsection 11(2)

(h) section 12

(i) section 14

(j) section 15

(k) paragraphs 19(1)(a), (c), (d), (f), (g) and (h), subsection 19(2) and paragraphs 19(4)(b) and (c)

(l) section 20

(m) section 21

(n) section 22

(o) section 25

(p) subsection 26(1)

(q) section 27

(r) subsection 30(1) and (3)

(s) subsection 32(1)

(t) subsection 35(1)

(u) section 36

(v) subsections 37(1) and (2)

(w) section 38

(x) subsections 39(1) and (2)

(y) section 42

(z) section 43

(z.1) subsection 47(1)
   

(z.2) section 48

(z.3) section 49

(z.4) subsection 50(3)

(z.5) section 51

(z.6) section 52

(z.7) section 53

Coming into Force

January 1, 2020

58 (1) Subject to subsection (2), these Regulations come into force on January 1, 2020.

January 1, 2023

(2) Sections 26, 27 and 37 to 41 of these Regulations and paragraphs 32(p), (q), (v), (w) and (x) of the schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999), as enacted by section 57 of these Regulations, come into force on January 1, 2023.

SCHEDULE 1

(Subsection 2(1) and 33(2))

Information for Extension of Period for Repair of Equipment Component

SCHEDULE 2

(Subsection 40(2))

Information for Permit for Pneumatic Pumps

SCHEDULE 3

(Subsections 54(1) and (3))

Information for Registration of a Facility

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Issues: Greenhouse gas (GHG) emissions are contributing to a global warming trend that is associated with climate change. Oil and gas facilities account for 26% of Canada’s total GHG emissions. These facilities are also Canada’s largest emitters of methane, a potent GHG and a short-lived climate pollutant (SLCP) with a global warming potential more than 25 times that of carbon dioxide (CO2).

Description: The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) [the Regulations] will introduce control measures (facility and equipment standards) to reduce fugitive and venting emissions of hydrocarbons, including methane, from the upstream oil and gas sector.

Cost-benefit statement: Between 2018 and 2035, the cumulative GHG emission reductions attributable to the Regulations are estimated to be approximately 232 megatonnes of carbon dioxide equivalent (Mt CO2e). Avoided climate change damages associated with these reductions are estimated at $11.6 billion. In addition, cumulative volatile organic compound (VOC) emission reductions are estimated to be 773 kt, with resulting health and environmental benefits estimated to be about $240 million. The total cost of the Regulations is estimated to be $3.9 billion, which will be offset in part by the recovery of 351 petajoules (PJ) footnote2 of natural gas, with an estimated value of $1.0 billion, resulting in expected net benefits of $8.9 billion.

“One-for-One” Rule and small business lens: The Regulations are expected to result in an increase in average annual administrative burden costs of about $1.8 million, or about $1,900 per business. The Regulations are therefore considered to be an “IN” under the Government of Canada’s “One-for-One” Rule.

The small business lens applies and various flexibilities have been incorporated into the Regulations to address the concerns of small businesses. The Regulations will result in cumulative costs of approximately $30 million for small businesses, or $53,000 per small business.

Domestic and international coordination and cooperation: The Regulations will deliver on the Government of Canada’s March 2016 commitment to reduce emissions of methane from the upstream oil and gas sector by 40% to 45% below 2012 levels by 2025. The Regulations are also consistent with Canada’s commitments under the Pan-Canadian Framework on Clean Growth and Climate Change, in which Canada resolved to implement its commitment under the Paris Agreement, to take action to reduce methane emissions from the oil and gas sector. Harmonization with provincial measures has been incorporated into the Regulations to the extent possible.

Background

Methane (CH4) is a hydrocarbon gas that is the main component of natural gas. In its pure state, methane is a colourless, odourless flammable gas and is considered a toxic substance listed under Schedule 1 of the Canadian Environmental Protection Act, 1999 (CEPA). It is a greenhouse gas (GHG) with a global warming potential 25 times greater than that of carbon dioxide (CO2) over a 100-year period. Oil and gas facilities account for 26% of Canada’s total GHG emissions and are Canada’s largest industrial emitters of methane. footnote3 The majority of these emissions are released by fugitive (unintentional release) and venting (intentional release) sources.

GHG emissions are contributing to a global warming trend that is associated with climate change, which is projected to lead to changes in average climate conditions and extreme weather events. The impacts of climate change are expected to worsen as the global average surface temperature becomes increasingly warmer. Climate change impacts are of major concern for society: changes in temperature and precipitation can impact natural habitats, agriculture and food supplies, and rising sea levels can threaten coastal communities.

Methane is a short-lived climate pollutant, which has a relatively short lifespan in the atmosphere compared to CO2 and other longer-lived GHGs. Considered over a 20-year period, methane has a global warming potential more than 70 times that of CO2 (compared to 25 times over a 100-year period). Atmospheric levels of methane thus respond relatively quickly to changes in emissions since they are removed quickly from the atmosphere. As a result of the potency and short lifespan of methane, reducing emissions has the potential to bring significant near-term climate benefits.

International and domestic commitments

At the United Nations Framework Convention on Climate Change (UNFCCC) conference in December 2015, the international community, including Canada, adopted the Paris Agreement, an accord intended to reduce global greenhouse gas emissions with a long-term goal of limiting the rise in global average temperature well below 2°C above pre-industrial levels and to aim to limit the temperature increase to 1.5°C. As part of its Nationally Determined Contribution (NDC) commitment under the Paris Agreement, Canada pledged to reduce national GHG emissions by 30% below 2005 levels by 2030.

On December 9, 2016, Prime Minister Trudeau, along with most first ministers of Canada, agreed to the Pan-Canadian Framework on Clean Growth and Climate Change (Pan-Canadian Framework). footnote4 The Pan-Canadian Framework was developed to establish a path forward to meet Canada’s commitments under the Paris Agreement. Within the Pan-Canadian Framework, the Government of Canada committed to various climate actions, including regulatory measures to take action on short-lived climate pollutants such as methane. To complement the Pan-Canadian Framework, the Government of Canada developed the Strategy on short-lived climate pollutants (SLCPs) in 2017 which aims to generate reductions from all key SLCP emission sources (e.g. methane, hydrofluorocarbons, and black carbon), including methane from oil and gas, and coordinate government mitigation efforts. footnote5

In March 2016, Canada adopted a target to reduce emissions of methane from its oil and gas sectors by 40% to 45% below 2012 levels by 2025. footnote6 To achieve this target, Canada committed to introducing federal regulations to reduce methane emissions from oil and gas facilities. footnote7 This commitment was reaffirmed in the Pan-Canadian Framework.

Hydrocarbons, natural gas and crude oil

Natural gas and crude oil are blends of various hydrocarbons extracted from deposits or reservoirs found beneath the surface of the earth and ocean floors. Hydrocarbons are molecules in various combinations of carbon and hydrogen. Hydrocarbons can be gas or liquid depending on their physical properties. Crude oil facilities extract liquid hydrocarbons, which can then be refined into gasoline, diesel, fuel oils, kerosene, jet fuel and other fuels, in addition to asphalt and road oil. Natural gas is a mixture consisting mostly of methane and is often used as fuel or to make materials and chemicals. Natural gas facilities extract, process and transport hydrocarbon gas. Natural gas and crude oil can often be found in association with each other in the same reservoir. As a result, crude oil facilities may also produce some natural gas, while natural gas facilities may also extract certain liquid hydrocarbons.

Emission sources in the oil and gas sector

The oil and gas industry encompasses many activities, from “upstream” activities, such as exploration, drilling, production and field processing, to “downstream” activities, such as petroleum refining and bulk storage and distribution of refined petroleum products. In 2014, close to 90% of methane emissions from the oil and gas sector originated from upstream activities. Major sources of hydrocarbon gas emissions from the upstream oil and gas sector are described below.

Facility production venting: General venting emissions from oil and gas facilities occur during the production process. This includes emissions from wellhead casings, processing equipment, and storage tanks. Releasing methane directly into the atmosphere has significant climate change consequences in comparison to flaring (burning) methane due to methane’s elevated global warming potential. Flaring converts methane into carbon dioxide, which has a much lower global warming potential.

Fugitive equipment leaks: Fugitive leaks may occur as a result of poor maintenance or regular wear and tear of equipment at all stages of production and processing of oil and gas. Leaks of gas or vapour may originate from equipment piping components such as valves, flanges, and connectors.

Well completion involving hydraulic fracturing: Well completion is the process of making a new well ready for production or stimulating an existing well to improve production, often through the use of hydraulic fracturing (or refracturing) techniques. Involving hydraulic fracturing, the well bore and formation must be cleaned of debris and fracturing fluid, a process that involves sending the well flowback material to an open pit or tank for disposal. Natural gas that is extracted along with the flowback material during this process is sometimes directly vented into the atmosphere.

Pneumatic controllers and pumps: Pneumatic controllers are used in the oil and gas industry to maintain and control parameters in the operations process, such as temperature, pressure, flow or liquid level, while pneumatic pumps are used to pump chemicals. It is common practice to use high-pressure field gas to operate these pneumatic devices.footnote8 In gas-driven pneumatic devices, natural gas may be released into the atmosphere with every instrument actuation, or continuously from the device.

Compressors: Compressors are mechanical devices that increase the pressure of natural gas and allow it to be transported from the well site where it is produced, through a system of smaller flow lines and field processing facilities to a larger pipeline system for eventual delivery to the consumer. Compressors can vent gas during regular use and venting increases as internal components wear.

Domestic emission control measures

Presently, there are no federal regulations established to regulate GHG emissions from the upstream oil and gas sector. Existing provincial instruments have the effect of controlling some methane emissions in British Columbia, Alberta and Saskatchewan, where the majority of onshore oil and gas activities occur. There are joint federal and provincial instruments for the offshore oil and gas sector in place for Nova Scotia and Newfoundland and Labrador. The Canadian Association of Petroleum Producers (CAPP) also has guidelines for flaring. However, these provincial instruments are not consistent across jurisdictions and do not cover all sources of fugitive and venting emissions.

In British Columbia, the Flaring and Venting Reduction Guideline applies to the flaring, incineration and venting of natural gas at well sites, facilities and pipelines. Other requirements exist for industry reporting of GHG emissions. To date, sources of venting and fugitive emissions in the oil and gas sector in British Columbia have not been subject to the provincial government’s carbon tax.

Alberta’s Directive 060 imposes gas conservation requirements by setting restrictions on incineration and venting in the province at all petroleum industry wells and facilities. Venting reduction through solution gas conservation or gas flaring is based on reported vented emissions from the entire facility.footnote9 Reported vented volumes include volumes from process vents, tank vents, and surface casing vents, but exclude venting from pneumatic instrumentation and pneumatic pumps. Further, Alberta has implemented the Carbon Competitiveness Incentive Regulation (CCIR) to replace the Specified Gas Emitters Regulations (SGER) which applies a system of output-based allocations to large emitters. These regulations will be phased in over a three-year period beginning in 2018.

Saskatchewan’s Directive S-10 sets out requirements for the reduction of flaring and venting of associated gas, applicable to oil wells, associated gas processing plants, and any wells that vent, flare, or incinerate associated gas. Likewise, Saskatchewan’s Directive S-20 provides performance requirements and specification for equipment spacing and setback distance specifications for oil and gas flaring and incineration, applicable to licensed wells and facilities. The S-10 and S-20 directives set out the main provincial requirements governing venting and flaring emissions.

In Canada’s offshore areas, venting and flaring are regulated through the Drilling and Production Regulations made under Canada Oil and Gas Operations Act, as well as the following Accord Acts: the Canada-Newfoundland and Labrador Atlantic Accord Implementation Act, and the Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act. Venting, flaring and total emissions limits and related mitigation measures are determined on a project by project basis and outlined in the project’s resource management plan and environmental protection plan. These limits are approved by the relevant offshore regulator as part of the project authorization process.

The Canadian Standards Association (CSA) develops voluntary codes some of which apply to the oil and gas sector. The Fugitive Emissions and Venting code specifies criteria to address fugitive and vented emissions from point sources from pipelines, wells and facilities in the upstream oil and gas sector. These standards specify criteria to develop emission reduction practices and programs.

Issues

GHGs, including methane and CO2, are contributing to a global warming trend that is associated with climate change. The largest source of GHG emissions in Canada is the extraction and processing of fossil fuels. The latest emissions data available indicate that GHG emissions from the oil and gas sector in Canada amounted to 189 Mt CO2e in 2015, accounting for 26% of total GHG emissions. footnote10 The oil and gas sector is also the largest contributor to methane emissions in Canada. Methane emissions from the oil and gas sector make up approximately 6% of Canada’s total GHG emissions. Methane is also a short-lived climate pollutant with a global warming impact more than 70 times greater than CO2 over a 20-year time period, making methane emissions a significant contributor to near-term global warming.

Current measures do not sufficiently control fugitive and venting methane emissions from the oil and gas sector. Without immediate action, it is expected that these fugitive and venting methane emissions in Canada will continue to be released at high levels of about 45 Mt CO2e per year between 2018 and 2035.footnote11

Objectives

The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) [the Regulations] aim to meet Canada’s commitment to reduce methane emissions from the oil and gas sector by 40–45% of 2012 levels by 2025. By meeting this objective, the Regulations will achieve significant reductions in GHG emissions through reductions in fugitive and venting emissions of hydrocarbon gases from the upstream oil and gas sector, thereby reducing future methane releases to the environment. This will reduce Canadian GHG emissions and help limit increases in global average temperatures, contributing to Canada’s international obligations to combat climate change. In addition, as methane is a short-lived climate pollutant with significant near-term climate impacts, these reductions will contribute to slowing the rate of near-term global warming.

Description

The Regulations will impose both general facility standards and standards that depend on a facility producing and receiving (potential to emit) at least 60 000 m3 of hydrocarbon gas in a year. The standards relate to production processes and equipment and will result in the reduction of methane and targeted VOCs emissions from the upstream oil and gas sector. These provisions will directly impact oil and gas facilities that contain equipment covered by the Regulations, such as:

The following standards apply to facilities with a potential to emit above 60 000 m3:

The following standards apply to all facilities:

All upstream oil and gas facilities will be required to register and keep records to demonstrate compliance with the Regulations. Facilities will also be required to submit reports at the request of the Minister.

The Department made notable modifications to the proposed Regulations in response to extensive consultation with stakeholders and departmental analysis of their feedback. The revisions are summarized in Table 1. Further information and analysis of these changes can be located in the Consultation section below.

Table 1: Summary of modifications from the proposed Regulations

Standard

Modifications made from proposed Regulations

Facility production venting

The facility venting limit was increased from 250 m³ to 1 250 m³ per month.

A method has been added to enhance quantification of estimated gas volumes.

Leak detection and repair

An allowance was added for alternate leak detection methods and instruments for LDAR if their use results in emission reductions equivalent to the reductions that would be achieved with the required inspection program.

Exemptions have been added for valve stations on pipelines and single wellheads with metering.

Additional time to complete repairs may now be granted through a permit.

A requirement has been added for LDAR at abandoned wells if they are part of a covered facility.

Well completion involving hydraulic fracturing

An allowance was added for venting when the gas cannot sustain combustion.

Pneumatic controllers and pumps

An exemption was added for sites when propane for use in pneumatics is brought on-site.

Zero-bleed pneumatic controllers are no longer required at any facility. Instead, a bleed rate limit of 0.17 m³ per hour must be met.

The chemical use threshold for pumps is now set at the site, not pump, level.

Compressors

An exemption has been added for compressors with a rated brake power less than 75 kW.

Time limits for repairs to reciprocating compressors have been extended from 30 days to 90 days.

The vent limit for large centrifugal compressors with a power rating above > 5 MW has been increased from 0.34 m³ per minute to 0.68 m³ per minute per compressor.

Vent limit of 0.001 m3 per minute for new reciprocating compressors will now be required, as opposed to conservation requirement.

General

Timeline for potential to emit calculations changed from largest of past five years to previous calendar year.

Offshore

A new section in the Regulations has been added for requirements specific to offshore operations.

Additional time to complete repairs in the offshore environment may now be granted through a permit.

Registration

Registration requirements have been modified and reduced to require facility level registrations only when a facility is not already registering to an approved entity.

The timeline for submitting registration has been extended to 120 days from the first day of production.

Accompanying the Regulations are consequential amendments to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) [the Designation Regulations]. The Designation Regulations designate the various provisions of regulations made under the Canadian Environmental Protection Act, 1999 (CEPA) that are linked to a fine regime following the successful prosecution of an offence involving harm or risk of harm to the environment or obstruction of authority. The Regulations will be listed in the Designation Regulations, which will require amendment.

Regulatory and non-regulatory options considered

When considering how to address the public policy issue, the Department considered five options: maintaining the status quo, using voluntary instruments, implementing a market-based approach, implementing regulatory emission control requirements that are closely aligned with the U.S. New Source Performance Standards (NSPS), or implementing Canada-specific regulatory emission control requirements.

Status quo approach

While British Columbia, Alberta, and Saskatchewan have measures to address venting methane emissions, there is no existing federal requirement in Canada to reduce GHG emissions from existing upstream oil and gas facilities. These provinces currently have some instruments in place for some aspects of the upstream oil and gas sector, such as British Columbia’s Flaring and Venting Reduction Guideline, Alberta’s Directive 060 and Saskatchewan’s directives S-10 and S-20. However, these instruments are not consistent across jurisdictions and do not cover all sources of emissions.

Therefore, current provincial measures alone would not deliver significant and achievable reductions in GHG emissions from the oil and gas sector, and may compromise Canada’s ability to meet its international commitments. Therefore, maintaining the status quo was not an acceptable option.

Voluntary approach

Voluntary instruments, such as pollution prevention plans, environmental release guidelines, and codes of practice were considered as options for methane mitigation. Voluntary instruments provide flexibility for stakeholders in meeting the objectives of the policy; however, they require a large degree of stakeholder participation and support.

The large number and diversity of facilities in the upstream oil and gas sector make it difficult to develop voluntary instruments capable of ensuring significant emission reductions. Uncertainty regarding buy-in by competitors under a voluntary measure may cause reluctance by firms to participate. While a voluntary program may result in some emission reductions, given its non-enforceable nature, it will not likely result in the emission reductions required to meet Canada’s GHG targets. Voluntary approaches were ultimately rejected for these reasons.

Market-based approach

In late 2016, the Government of Canada announced a plan to price carbon (and other GHG) pollution across Canada as part of the Pan-Canadian Framework. The proposed federal approach to carbon pricing would not cover fugitive and venting methane emissions in the oil and gas sector. These emissions often originate from dispersed sources from a large number of primarily small facilities, which are unlikely to have adequate quantification protocols for tracking emissions. Therefore, a regulatory approach was considered necessary to meet the emission reduction objective.

Regulatory approach — Canada–United States alignment (new source performance standards)

A regulatory approach designed to align closely with the current U.S. approach (NSPS) was considered. However, such an approach would not be consistent with existing provincial measures, resulting in misalignment within Canada. This approach would not capture unique Canadian emission sources, such as heavy oil, and will impose substantial, unnecessary administrative burden on regulated parties. This approach would also be inconsistent with commitments in Canada’s Cabinet Directive on Regulatory Management to control the administrative burden of regulations on business. Finally, the approach would not initially cover a significant portion of existing facilities, making it difficult to meet the reduction targets announced by the Government of Canada in 2016. For these reasons, while there is general alignment, precise alignment with the U.S. NSPS was rejected.

Regulatory approach — industry proposal

In comments received from the oil and gas industry, including CAPP, an alternative approach to regulating methane emissions from vented and fugitive sources was proposed. This approach eliminated the potential to emit threshold, introduced a higher venting limit, and included a risk-based approach to LDAR. The Department considered this proposal; however, after estimating the emission reductions the proposal would achieve, determined that the proposal would not be sufficient to meet the reduction target announced by the Government of Canada. Therefore, this alternative was rejected.

Federal regulatory approach

The Government of Canada is committed to reducing GHG emissions, including methane, in light of Canada’s international agreements. Regulations implemented under CEPA are effective at achieving emissions reductions and are among the primary instruments to achieving this goal. This approach ensures that hydrocarbon gas emissions, including methane, are controlled and reduced from sources in a consistent fashion across Canada from similar sources in the upstream oil and gas industry.

The Regulations will create clear and consistent performance standards across the country. CEPA allows for flexibility via equivalency agreements with interested provinces and territories, as long as the requirements of CEPA are met. These equivalency agreements enable these jurisdictions to be front-line regulators where they have legally binding regimes that produce equal or better environmental outcomes.

The Regulations will exempt the provinces of British Columbia and Alberta from the well completion involving hydraulic fracturing requirements. These provinces already have regulatory measures in place that require operators to flare or incinerate gas during temporary activities and to search for opportunities to reduce their flaring and incinerating. The well completion involving hydraulic fracturing requirements under the Regulations will instead cover the rest of Canada, where similar provincial requirements are not in place.

Benefits and costs

Between 2018 and 2035, the cumulative GHG emission reductions attributable to the Regulations are estimated to be approximately 232 Mt CO2e. Avoided climate change damages associated with these reductions are valued at $11.6 billion. In addition, cumulative VOC emission reductions are estimated to be 773 kt, with resulting health and environmental benefits estimated to be $240 million. The total cost of the Regulations is estimated to be $3.9 billion, which will be offset in part by the recovery of 351 petajoules (PJ)footnote12 of natural gas, with a market value of $1.0 billion, resulting in expected net benefits of $8.9 billion.

As shown in Figure 1 below, the most significant costs will be incurred in 2022 and 2023, as firms make significant capital investment in order to comply with requirements coming into force in 2023. Beyond 2023, it is expected that emissions of methane will be reduced by more than 16 Mt (in CO2e) annually. In 2025, the regulations will require actions that are estimated to result in total reductions of 20 Mt, of which 4 Mt have been attributed to voluntary industry action. In 2030, there will be net GHG emission reductions of about 16.5 Mt.

Figure 1: Methane emission reductions and compliance costs by year

Detailed information can be found in the surrounding text. / Des renseignements complémentaires se trouvent dans les paragraphes adjacents.

Detailed information can be found in the surrounding text. / Des renseignements complémentaires se trouvent dans les paragraphes adjacents.

Analytical framework

TBS guidance: The impacts of the Regulations have been assessed in accordance with the Treasury Board Secretariat (TBS) Canadian Cost-Benefit Analysis Guide.footnote13 Regulatory impacts have been identified, quantified and monetized where possible, and compared incrementally to a non-regulatory scenario. The analysis has estimated these impacts over a sufficient time period to demonstrate whether there is likely to be a net benefit.

Key impacts: The expected key impacts of the Regulations are demonstrated in the logic model (Figure 2) below. Compliance with the Regulations will result in incremental capital and operating costs for industry, and administrative costs for both industry and Government. Compliance will also result in reduced releases of natural gas (a mixture consisting of mostly methane and VOCs), which will reduce releases of GHGs and VOCsfootnote14 to the atmosphere. Reductions in GHG emissions from the upstream oil and gas sector will contribute towards mitigating climate change impacts. Reductions in VOCs will improve air quality which results in environmental and health co-benefits. Methane gas that would have otherwise been lost through fugitive leaks or venting will now be conserved as a potential energy source or flared.

Figure 2: Logic model for the analysis of the Regulations

Logic model for the analysis of the Regulations

Compliance with the Regulations

→

Reductions in GHG Emissions

→

Reduction in Climate Change Damages

→

Social Benefits

→

Reductions in VOC Emissions

→

Improved Air Quality

→

→

Conserved Gas

→

Increased Conservation

→

 

→

Compliance Costs

→

Social Costs

Administrative Costs

→

Baseline scenario: The baseline scenario assumes fugitive and venting emissions of methane and VOCs will be unchanged relative to projected levels in the absence of regulatory measures. In order to ensure a conservative assessment of benefits for the purposes of this analysis, independent industry action to reduce venting volumes has been incorporated into the baseline scenario. Existing provincial measures on limiting methane emissions from oil and gas facilities are included in the baseline.

Regulatory scenario: The analysis compares the expected impacts of the Regulations (the regulatory scenario) to a non-regulatory scenario that assumes these regulatory measures are not implemented (the baseline scenario). All benefits and costs presented below are incremental to the baseline scenario, unless otherwise specified.

Time frame of analysis: The time frame considered for this analysis is 2018 to 2035. Some early compliance at new facilities is expected starting in 2018. Incremental costs and benefits beyond 2023 are estimated to be correlated with oil and gas production forecasts from the National Energy Board (NEB), which are available up to 2035. Benefits exceed costs in any given year beyond 2023. Therefore, the 2018-2035 time frame was considered sufficient for estimating whether the Regulations will result in a net benefit. A longer time period of analysis will show a larger net benefit because most of the costs of the Regulations are upfront costs incurred in 2023, as shown in Figure 1 above.

Monetary results: All monetary results are shown in 2016 Canadian dollars, inflating non-2016 prices (using GDP Deflator data obtained from Finance Canada), and converting non-Canadian prices (2016 exchange rates). When shown as present values, future year impacts have been discounted at 3% per year to 2017 (the year of the analysis), as per TBS guidance.

Updates to the analysis following publication of the proposed Regulations in Canada Gazette, Part I (CG-I)

Analytical updates

Comments received following the publication of the proposed Regulations included feedback from stakeholders regarding the Regulatory Impact Analysis Statement. In addition, following publication in CG-I, the Department engaged with provincial partners, industry stakeholders, and non-governmental organizations to review modelling assumptions used in the analysis of the proposed Regulations. In response, the following substantive changes have been made to the analysis:

In addition, price levels and exchange rates have been updated to align with the most up-to-date information, and the base year to discount costs and benefits to present value has been updated to 2017. In total, these analytical changes have led to an increase in estimated costs from $3.3 billion estimated in CG-I to $4.4 billion. Emission reductions attributable to the proposed Regulations have decreased from 282 Mt to 245 Mt, with 69 Mt now being attributed to industry action that is expected to occur in the absence of regulatory measures.

Regulatory updates

Based on the comments received following the publication of the proposed Regulations in Canada Gazette, Part I, minor modifications have been made to the Regulations, as outlined in the Description section above. These modifications are estimated to result in a reduction of costs from $4.4 billion to $3.9 billion, while emissions reductions over the period of analysis are estimated to decrease from 245 Mt to 232 Mt.

Analysis of regulatory coverage and compliance

To estimate the incremental benefits and costs of the Regulations, the analysis considered who will be affected (regulatory coverage) and how they will most likely respond (their compliance strategies), as described below.

Regulatory coverage

The Regulations will target emissions from the upstream oil and gas sector by implementing facility and equipment level requirements. Facility level requirements will include emission limits on facility production venting and LDAR standards. At the equipment level, there will be requirements for well completion involving hydraulic fracturing, as well as limits on emissions from pneumatic devices (controllers and pumps) and compressors.

The Regulations will cover facilities that exceed the potential to emit threshold, defined as 60 000 m3 of hydrocarbons produced and received in a period of 12 months, facilities with compressors subject to the standards, and those completing wells involving hydraulic fracturing (covered facilities). Currently, some facilities are expected to already meet the compliance requirements of the Regulations due to current provincial measures or voluntary action. Facilities that will need to take incremental action to comply with the Regulations are considered affected facilities. The cost-benefit analysis focuses on affected facilities when estimating incremental impacts of the Regulations.

In order to estimate affected and covered facilities in the oil and gas sector, 2016 Petrinex (Petroleum Information Network) footnote16 upstream oil and gas facility counts for Alberta and Saskatchewan were used, and forecasted using the production forecasts of crude oil and natural gas from the NEB.footnote17 Due to limited available information, the number of facilities in the rest of Canada was forecasted using production profiles calculated for Alberta and Saskatchewan. Feedback from British Columbia officials allowed the derived facility count for that province to be adjusted. Other producing regions reflect similar efforts.

Regulatory compliance

The Regulations do not prescribe unique actions to comply with the requirements. However, for modelling purposes, assumptions have been made regarding specific compliance actions in order to estimate costs and benefits. The compliance actions assumed to be adopted by the upstream oil and gas industry in order to meet the requirements for each standard under the Regulations are described below.

LDAR requirements

The Regulations will allow different leak detection instruments to be used for inspections at covered facilities. For portable monitoring instruments and optical gas imaging (OGI) cameras, inspections must take place three times per year. Other approaches must be shown to achieve emission reductions comparable to reductions achieved if portable monitoring or OGI instruments were used.

Based on industry consultation, it is expected that in the baseline scenario, facilities not covered by provincial regulatory measures will perform LDAR about once every four years. For facilities covered by provincial regulatory measures, gas plants are expected to perform LDAR every year, while all other facilities are expected to perform LDAR once every two years in the baseline scenario.

The analysis assumes that to comply with the Regulations, affected facilities will perform LDAR with an optical gas imaging (OGI) camera three times a year. Should a leak be detected, a facility will be required to repair the leak and reinspect the leak using a portable monitoring instrument.

Compressor requirements

For existing reciprocating and centrifugal compressors whose vented emissions are not being captured or destroyed, the Regulations will set emissions limits. Corrective action is required if those emissions exceed 0.023 m3 per minute per rod packing for reciprocating compressors, or 0.34 m3 per minute per compressor for centrifugal compressors. Large centrifugal compressors with a rated brake power over 5 MW power will be subject to an emission limit of 0.68 m3 per minute per compressor. After corrective action is taken, the rate of emissions must be measured again. In addition, any compressors installed after January 1, 2023, must meet a limit of 0.001 m3 per minute per rod packing for reciprocating compressors and 0.14 m3 per minute per compressor for centrifugal compressors.

It is expected that affected facilities with reciprocating compressors will, on average, replace rod packings every three years in the regulatory scenario compared to replacement every four years in the baseline scenario. It is expected that facilities with newly installed compressors, where a flare is not already present, will install a capture device and either route vented gas to engine as fuel or to an existing flare.

Affected facilities with centrifugal compressors with wet seals are expected to install recovery systems on their wet seal degassing units to recover and reroute vented gas. The degassing recovery system will allow facilities with wet seals to forego retrofitting their compressors with dry seals and still mitigate methane emissions with little downtime. It is assumed new centrifugal compressors would comply with the requirements in the absence of the Regulations.

Well completion involving hydraulic fracturing requirements

The Regulations will require hydraulic fracturing operations to conserve or destroy vented gas, except in British Columbia and Alberta (where equivalent provincial requirements exist). In the baseline scenario, it is expected that about 25% of covered wells are currently flaring emitted gas during this process while the rest are venting emitted gas. For the regulatory scenario, it is assumed that all well completions involving hydraulic fracturing wells will flare emitted gases to comply with the Regulations, although conservation remains a viable compliance option.

Facility production venting requirements

The Regulations will require covered facilities to limit vented gas to 15 000 m3 per year. Affected facilities will comply with the Regulations either by destroying or conserving vented gas. It is assumed that it will be less costly for a facility to conserve its vented gas if its gas production minus on-site fuel use is greater than 750 000 m3 per year. Also, if the facility is already selling more than 20 000 m3 of gas per year, it is assumed that it will conserve gas. If neither of these conditions is met, it is assumed the facility will combust the gas. Installation of the necessary equipment to comply with these requirements will occur over a two-year period beginning in 2022.

Pneumatic controller and pump requirements

The Regulations will require affected facilities with pneumatic controllers to use low bleed controllers, and affected facilities with pneumatic pumps pumping over 20 L of liquid per day to be non-emitting.

For non-compliant pneumatic controllers, it is assumed that existing facilities will either retrofit current pneumatic controllers, or replace controllers with low-bleed controllers. New facilities will purchase and install low bleed devices. Pneumatic pumps at batteries and well sites are assumed to be replaced with solar pumps.

For existing facilities, it is assumed that devices will be replaced over a two-year period beginning in 2022. It is assumed that new facilities will purchase low-bleed controllers or solar pumps, beginning in 2018.

Table 2: Expected compliance strategies by standard

Standard

Year of Coming Into Force

Assumed Compliance Action

LDAR

2020

Leak detection will be performed with OGI camera three times per year.

Repaired leaks will be reinspected with portable monitoring instrument.

Well completion involving hydraulic fracturing requirements

2020

Fractured and refractured wells will flare emitted gases.

Compressors

2020

Rod packing in reciprocating compressors will be replaced every three years instead of four years.

New reciprocating compressors will install vent capture device, and re-route to engine or flare.

Centrifugal compressors with wet seals will install recovery unit on wet seal degassing system.

Facility production venting requirements

2023

Facilities with net gas production greater than 750 000 m3 per year, or with gas sales greater than 20 000 m3 per year will conserve vented gas.

Other facilities (i.e. with lower production or sales) will destroy gas.

Pneumatics

2023

High-bleed controllers will be replaced with low-bleed controllers or retrofitted at existing facilities.

Low-bleed controllers will be installed at new facilities.

Pneumatic pumps will be replaced with electric (solar) pumps.

Note: These assumptions are not intended to represent the entirety of available compliance actions, or to prescribe specific actions to comply with the Regulations.

Industry costs of compliance by standard

Facilities covered by the Regulations are expected to incur incremental capital and operating costs in order to comply with each standard. Both industry and the federal government are also expected to incur some administrative costs in order to ensure regulatory compliance. Due to uncertainty of both cost estimates and future compliance actions, these costs may underestimate or overestimate future compliance costs. This uncertainty is addressed in the sensitivity analysis section below.

LDAR compliance costs

The Regulations will impose compliance costs on affected facilities due to increased frequency of leak detection compared to the baseline scenario. Compliance costs to industry will include the capital cost of putting in place an LDAR data collection system of $3,000–$5,000 per facility.footnote18 Costs will also be incurred for OGI cameras of $133,000 per camera, and trucks to transport technicians and equipment to sites of $50,000 per vehicle.footnote19,footnote20 In addition, costs will be incurred to detect leaks using OGI equipment. The number of components per facility is used to estimate the time it will take to conduct OGI leak detection, assumed to cost $190 an hour for technicians to perform LDAR and travel between sites.footnote21 Upon completion of a repair, the Regulations require that the repaired leak be inspected using a portable monitoring instrument in accordance with the U.S. Environmental Protection Agency Method 21. Table 3 below provides a summary of LDAR costs by facility type. It is estimated that the LDAR requirements will result in a cost to industry of $1,204 million between 2018 and 2035.

Table 3: Compliance costs for LDAR requirements

Facility Type

Time/Inspection (Hours) including travel time

Annual Cost/Facility

Upfront Cost/Facilityfootnote22

Number of Affected Facilities

Total (2018–2035; in millions)

Oil Single Well Battery

2.5

1,425

3,400

12 600

195

Oil Multi-well Battery

2.7

1,540

3,400

6 020

98

Gas Single Well Battery

3.0

2,710

3,500

8 680

142

Gas Multi-well Battery

5.7

3,250

4,000

7 830

234

Compressor Station

11.5

5,990

5,000

7 290

427

Gas Plant

19.0

9,690

7,700

780

66

Meter Station

1.4

800

100

2 440

42

Total

-

-

-

45 640

1,204

Note: Affected facility totals represent all new and existing facilities over the period of analysis. Total costs are discounted at 3%.

The analysis assumes that leaks are random and independent events and that new leaks are unlikely to reoccur within the baseline reinspection period (two to four years). Therefore, the number of leaks that are detected and repaired in the baseline and regulatory scenarios are expected to be similar. Under the regulatory scenario, leaks will be detected earlier than they will in the baseline scenario, leading to emissions reductions. As the number of leaks detected is not expected to change significantly, the analysis has not considered the incremental cost of repairs.

Compressors compliance costs

Facilities with existing reciprocating compressors are expected to replace rod packing more frequently as a result of the Regulations. Rod packing replacement is expected to cost $3,000 per cylinder, with a typical compressor containing between two and six cylinders. The baseline scenario assumes rod-packing replacement is occurring every four years, compared to every three years in the policy scenario. The incremental cost of this increased rod-packing replacement is estimated at an annualized cost of $250 per cylinder. In addition, annual metering costs of $200 per compressor will be incurred to measure vent rates from reciprocating seals for compressors whose emissions are not already being captured.

It is estimated that about 3 790 newly-installed reciprocating compressors will be required to capture or destroy all emitted gases.footnote23 In most cases, costs will be incurred to install conservation equipment, approximately $37,000 per compressor, with operating costs of about $800 annually. In cases where capturing vented gases isn’t feasible, it is assumed facilities will route emitted gases to an existing flare at an upfront cost of $45,000 with operating costs of about $5,000 annually.footnote24

Facilities with centrifugal compressors are expected to augment their compressors with a recovery unit that conserves vented gas from the compressor’s wet seal degassing system. It is estimated that there are about 130 affected centrifugal compressors, and the cost of installing a wet seal degassing system is estimated to be $45,000. It is estimated that the compressor standard will result in a cost to industry of $279 million between 2018 and 2035.

Table 4: Compliance costs for compressor requirements

Compliance Action

Capital Cost/Compressor (including install)

Annual Operating Cost/Compressor

Number of affected compressors

Total Cost (2018–2035; in millions)

Existing Reciprocating — Rod-packing Replacementfootnote25

-

750–1,500

7 610

132

New Reciprocating — Capture device footnote26

37,000

800

3 030

108

New Reciprocating — Re-route gas to existing flarefootnote27

45,000

5,000

760

34

Existing Centrifugal — Wet seal degassing systemfootnote28

45,000

-

130

5

Total

    

11 530

279

Note: Affected compressor totals represent all new and existing compressors over the period of analysis. Total costs are discounted at 3%.

Well completion involving hydraulic fracturing requirements compliance costs

The analysis assumes that, under the regulatory scenario, all affected fracturing and re-fracturing wells outside of Alberta and British Columbia (which are exempt) will flare emitted gases during the well completion process. It is estimated that about 24 000 oil and gas wells will be required to install a flare over the time frame of the analysis. It is expected that flaring well completion requirements will cost $6,200 per completion (flares required for well completions are generally rented on a temporary basis and are therefore less costly than facility flaring described above). It is estimated that this standard will result in a cost to industry of $123 million between 2018 and 2035.

Table 5: Compliance costs for well completions involving hydraulic fracturing

Compliance Action

Rental Cost

Number of affected wells

Total Cost (2018–2035; in millions)

Flarefootnote29

6,200

24 140

123

Note: Total costs in millions, discounted to present value at 3%

Facility production venting compliance costs

Costs will be incurred by affected facilities in order to either conserve previously vented gas by installing a vapour recovery unit (VRU), or to install a flare or incinerator to destroy the gas. It is estimated that about 760 facilities will conserve gas, while about 6 830 facilities will flare it. Compliance costs borne by industry will include the operating costs associated with ongoing operation and management, and capital costs for VRU and flares. Capital costs are estimated to average $130,000 per facility to purchase and install a VRU, and $130,000 per facility to purchase and install a flare or incinerator.footnote30 Annual operating costs are estimated at $7,500 per facility to conserve gas, and at $7,500 per facility to flare. The facility production venting standard will result in an estimated cost to industry of $1,273 million between 2018 and 2035.

Table 6: Compliance costs for facility production venting requirements

Compliance Action

Capital Cost/Facility

Annual Operating Cost/Facility

Number of Affected Facilities

Total Cost (2018–2035; in millions)

VRUfootnote31

130,000

7,500

760

129

Flare/Incinerator/Enclosed Combustorfootnote32

130,000

7,500

6 830

1,144

Total

-

-

7 590

1,273

Note: Affected facility totals represent all new and existing facilities over the period of analysis. Total costs are discounted at 3%.

Pneumatic controllers and pumps compliance costs

The analysis calculates the number of pneumatic devices affected by multiplying the number of affected facilities by an estimated number of devices per facility. It is assumed that new facilities will incur the incremental cost difference between a high-bleed device and a compliant device. Existing facilities will incur either the full cost of a new device, or the cost to retrofit existing devices. In cases in which pneumatic controllers do not have manufacturer’s operating specifications, annual measurement of the controller is required.

Incremental compliance costs incurred by existing facilities would be $1,150 per controller retrofit, and $2,100 per controller replacement. For the approximately 10 % of existing controllers without manufacturer’s operating specifications, an additional cost of $200 per year is expected to perform annual measurement. For new facilities, the incremental cost of installing a low bleed controller is assumed to be $300. For pneumatic pumps, it is assumed that facilities will replace pumps with solar pumps, which is estimated to cost $7,500 for new facilities and $16,200 for existing facilities. It is estimated that the pneumatics standard will result in a cost to industry of $999 million between 2018 and 2035.

Table 7: Compliance costs for pneumatic controllers and pumps

Compliance Action

Capital Cost (including installation cost)

Annual Operating Costfootnote33

Number of affected devices

Total Cost (2018–2035; in millions)

High to low bleed controller retrofitfootnote34

1,150

20

86 810

72

Replacement of high-bleed with low-bleed

2,100

20

68 850

107

Incremental cost of low-bleed for new facilities

300

-

101 260

25

Replacement of high-bleed pumps with solar pumpsfootnote35

16,200

  

65 200

633

Incremental cost of solar pumps for new facilities

7,500

  

30 640

162

Total

-

-

352 750

999

Note: Affected device totals represent all new and existing devices over the period of analysis. Total costs are discounted at 3%.

Summary of industry compliance costs

Compliance costs associated with the Regulations are estimated at $3.9 billion over the period of analysis. Almost half of the compliance costs are expected to occur in 2022 and 2023 (about $1.7 billion as shown in Figure 1 above), when the facility production venting, and pneumatic device and pump requirements come into effect. Estimates of total compliance costs for each standard are shown in Table 8 below.

Table 8: Industry compliance costs by standard (millions of dollars)

Standard

2018–2025

2026–2030

2031–2035

Total

Leak detection and repair

554

351

300

1,205

Compressors

89

97

94

279

Well completion involving hydraulic fracturing requirements

52

33

28

113

Facility production venting requirements

799

252

222

1,273

Pneumatic controllers and pumps

910

47

41

999

Total

2,405

780

685

3,870

Note: Numbers may not add up due to rounding. Monetized values are discounted to present value using a 3% discount rate.

Industry and government administrative costs to ensure compliance

Presently, there are no federal regulations established to regulate GHG emissions in the oil and gas sector. The Regulations will require facilities to register if they are not already reporting to an approved entity, and facilities to keep records, and submit reports on demand. These industry administrative costs are estimated to be $42 million between 2018 and 2035.footnote36

The Department will also incur costs to enforce the Regulations, conduct compliance promotion and administer the Regulations.

With respect to enforcement costs, an estimated one-time cost of about $350,000 is expected to be required for the training of enforcement officers, $1,700 to meet information management requirements, and $96,800 for intelligence assessment work. The annual enforcement costs are estimated to be $390,600, which includes $214,500 for inspections and measures to deal with alleged violations, about $41,000 for investigations, about $135,000 for prosecutions, and about $6,800 for recurring training. In total, enforcement costs are estimated to be $6.3 million between 2018 and 2035.

Compliance promotion activities are intended to encourage the regulated community to achieve compliance. Compliance promotion costs include distributing the Regulations electronically, developing and distributing promotional materials (such as a fact sheet and web material), advertising in trade and association magazines and attending trade association conferences. This cost is estimated to be $150,000 between 2018 and 2022.

The Regulations allow for a temporary permitted exemption for facilities where meeting certain requirements will be technically or economically infeasible. These permits will need to be reviewed and approved by the Government of Canada. The total cost of permit reviews is estimated to be $280,000 between 2018 and 2035.

Table 9 below summarizes the administrative cost to ensure compliance for both industry and Government.

Table 9: Administrative costs for industry and Government (millions of dollars)

 

2018–2025

2026–2030

2031–2035

Total

Industry administrative costs

18

13

11

42

Government administrative costs

4

2

1

7

Total administrative costs

22

14

12

49

Note: Numbers may not add up due to rounding. Monetized values are discounted to present value using a 3% discount rate.

Administrative costs to industry and Government necessary to ensure compliance are estimated to be $49 million between 2018 and 2035.

Benefits of regulatory coverage and compliance

The Regulations will reduce vented and fugitive emissions of methane, a potent GHG and short-lived climate pollutant, through the requirements to conserve or destroy fugitive and vented natural gas. This means that some natural gas that would have otherwise been wasted will be conserved as a potential energy source. In addition, emissions of VOCs will be reduced, leading to improved air quality, which can improve the environment and health of Canadians.

To monetize the benefits, the social cost of carbon (SCC) has been applied to the expected CO2 emissions, and the social cost of methane (SCCH4) has been applied to the expected methane (CH4) emission reductions to value the avoided climate change damages resulting from reductions in GHG emissions. A market price for natural gas has been applied to value the amount of gas conserved. Health and environmental benefits attributed to reductions in VOCs have been estimated based on a scenario analysis concluded in 2016.

Quantification of benefits

The analysis estimated the conserved gas and quantified the emission reductions by first developing detailed engineering emissions estimates for the baseline and regulatory scenario, and then scaling these to the Department’s overall emission estimates for the oil and gas sector in order to ensure that the estimates are consistent.

To calculate venting and fugitive gas reductions, baseline and policy emission factors for the various standards and product types were multiplied by the total number of devices or facilities for the respective standard. This procedure calculates the total amount of gas that will be emitted with and without the Regulations. The difference between the emissions in the baseline scenario and the emissions in the regulatory scenario were used to estimate the incremental reductions.

The sources for the emission factors differ for each standard.

To determine emissions of the various pollutants contained in emitted gases, the composition of gas streams is determined using estimates of gas composition from the Clearstone Engineering report,footnote42 with the exception of gas from facility production venting, as these composition ratios were obtained from a combination of reports from provinces.footnote43 To obtain the amounts of CO2, CH4 or VOCs reduced, the natural gas reductions are multiplied by the composition ratios for each standard which are provided in Table 10 below.

Table 10: Composition of gas by standard and product type

Standard

Product Type

CO2

CH4

VOCs

Venting

Light oil

10%

53%

22%

Venting

Heavy oil

6%

89%

2%

Venting

Cold heavy oil with sand (CHOPS)

2%

94%

1%

All others

Light oil

1%

84%

4%

All others

Heavy oil

1%

84%

4%

All others

Non-associated gas

2%

88%

5%

All others

Tight gas

>1%

94%

2%

All others

Shale gas

>1%

94%

2%

All others

Coal bed methane gas

>1%

96%

1%

All others

Gas processing

2%

88%

5%

The engineering emission estimates were then scaled to align with the departmental baseline emissions forecasts. The departmental baseline emission projections for the oil and gas sector are determined using the production forecast of oil and gas from the NEB, in combination with the National Inventory Report. These departmental projections are developed in the Energy, Emissions and Economy model (E3MC), one of the Department’s models for developing GHG emission projections and analyzing policy impacts in Canada. This analysis uses emissions projections as reported in Canada’s 2016 Greenhouse Gas Emissions Reference Case.footnote44

The engineering estimates were used to derive a baseline for all fugitive and venting emissions, which was calculated for five provinces; British Columbia, Alberta, Saskatchewan, Manitoba and Ontario, and five sectors; natural gas production, natural gas processing, heavy oil mining, light oil mining, and natural gas pipelines. The mapping of these sectors between E3MC and the engineering model, in addition to how emissions are characterized in the analysis below, is shown in Figure 3 below.

Figure 3: Sector mapping between key models

E3MC

  

Engineering Model

  

RIAS analysis

Natural gas production

→

Tight gas

→

Natural gas production

Shale gas

Non-associated gas

Coalbed methane gas

Compressor stations

→

Natural gas processing

Natural gas processing

→

Gas plants

Heavy oil mining

→

Heavy oil mining (includes CHOPS)

→

Heavy oil mining

Primary Oil Sands

Light oil mining

→

Light oil mining

→

Light oil mining

Natural gas pipelines

→

Natural gas pipelines

→

Natural gas pipelines

The engineering baseline estimates were compared to the departmental baseline emissions forecast for these provinces and sectors to obtain a set of ratios, or scaling factors, as follows:

Detailed information can be found in the surrounding text. / Des renseignements complémentaires se trouvent dans les paragraphes adjacents.

These scaling factors were then applied to the engineering reduction estimates for each pollutant and for estimates of conserved gas to derive final incremental estimates for the Regulations.

Production and venting data reported to the provinces in 2016 showed a significant reduction in venting volumes, with increasing fuel use of gas on site, which is understood to be the result of industry action. As the current departmental baseline includes historic data up to 2014, this 2016 reduction in emissions is not included. To reflect changes in the latest reported data, the baseline was adjusted to account for these reductions. The analysis has thus attributed these emission reductions to industry action, which are estimated at about 4Mt annually (see Figure 4 below).

Greenhouse gas emission reductions

The Regulations will reduce methane emissions that would otherwise be emitted into the atmosphere. At the same time, the Regulations are estimated to result in a slight increase in flaring activities, which will slightly increase CO2 emissions. The Regulations will reduce 9.9 Mt of methane emissions over the time frame of analysis. Using a global warming potential factor of 25, the decrease in methane emissions is estimated at 247 Mt CO2e between 2018 and 2035. The increase in CO2 as a result of the increase in flaring activities is estimated to be 15 Mt over the time frame of analysis. Emissions in the baseline and policy scenarios are demonstrated in Figure 4 below, with the difference representing emission reductions attributable to the Regulations.

Figure 4: Baseline and policy methane emissions (2012–2035)

Detailed information can be found in the surrounding text. / Des renseignements complémentaires se trouvent dans les paragraphes adjacents.

The net GHG emission reductions are measured as the combined reductions of CH4 and CO2, as well as the increase in CO2 emissions from increased flaring. It is estimated that a net 232 Mt CO2e of GHG emissions will be reduced between 2018 and 2035 as a result of the Regulations as seen in Table 11 below.

Table 11: GHG emission reductions per standard (in Mt CO2e)

 

Net GHGs (CH4 + CO2)

CH4

CO2

Standard

2018–2025

2026–2030

2031–2035

2018–2035

2018–2035

2018–2035

Facility production venting requirements

22

32

32

86

101

-15

Leak detection and repairs

19

16

16

52

52

0

Well completion involving hydraulic fracturing requirements

2

1

1

4

5

-1

Pneumatic controllers and pumps

20

28

28

76

76

0

Compressors

4

5

5

14

14

0

Total

67

83

82

232

247

-15

Note: Numbers may not add up due to rounding. CO2 emissions increase as a result of facilities flaring vented gas. Methane (CH4) emissions are presented in Mt CO2e, which is calculated by multiplying methane emission reductions by a global warming potential of 25.

The impacts of reducing GHG emissions in the atmosphere were valued using the departmental SCCH4 and SCC.footnote45 The SCCH4 and SCC represent estimates of the economic value of avoided climate change damages at the global level for current and future generations (from present day to 2300) as a result of reducing CH4 and CO2 emissions over the time frame of analysis (2018–2035).

Estimated values of the SCCH4 range from $1,288 in 2018 to $2,050 in 2035, while estimates of the SCC range from $45 in 2018 to $62 in 2035. Over the time frame of analysis, the SCCH4 is applied to 247 Mt of methane reductions and the SCC is applied to 15 Mt increase in CO2 as a result of flaring. The estimated present value of the reduction of GHGs is about $11.6 billion.

Table 12: Total present value of GHG emission reductions (millions of dollars)

Standard

2018–2025

2026–2030

2031–2035

Total

Facility production venting requirements

1,123

1,649

1,603

4,376

Leak detection and repairs

967

811

771

2,548

Well completion involving hydraulic fracturing requirements

97

60

48

205

Pneumatic controllers and pumps

988

1,394

1,381

3,764

Compressors

221

234

240

695

Total

3,396

4,148

4,044

11,588

Note: Numbers may not add up due to rounding. Monetized values are discounted to present value using a 3% discount rate. The SCCH4 is applied to the reduction of methane emissions while the SCC is applied to the increase in CO2 emissions.

Contribution to national oil and gas methane target

In March 2016, Canada adopted a target to reduce emissions of methane from their oil and gas sectors by 40% to 45% below 2012 levels by 2025. It is expected that the Regulations will lead to a 16.4 Mt reduction in methane emissions in 2025, which combined with the estimated 4Mt reduction attributed to industry action for the purposes of this analysis would lead to a reduction of 40% below 2012 levels. It is important to note that in the absence of this estimated industry action, equivalent measures will be required by the regulations, thus, ensuring the approximately 20 Mt of reductions required for the attainment of the target.

Contribution to Paris Agreement commitment (emission reductions in 2030)

Canada committed to reduce GHG emissions by 30% below 2005 levels by 2030 under the Paris Agreement. In December 2016, the Department estimated that annual emission reductions of 219 Mt CO2e will be required in 2030 to deliver on this commitment. GHG reductions from the Regulations (16.5 Mt) will contribute 8% to Canada’s GHG emissions reduction target (219 Mt) under the Paris Agreement.footnote46 For the Regulations, the cumulative GHG emission reductions between 2018 and 2030 are estimated to be 150 Mt CO2e.

Contribution to Pan-Canadian Framework

The Pan-Canadian Framework was developed to establish a comprehensive plan to meet Canada’s commitments under the Paris Agreement. The Framework proposed a range of complementary climate actions to support pricing carbon pollution in reducing GHG emissions. The Regulations are one such measure that will reduce emissions in a complementary fashion to carbon pricing systems across Canada.

VOC emission reductions

The Regulations, through reductions of fugitive and venting emissions, will also reduce by up to 773 kt the quantity of VOCs that would have entered the atmosphere over the time frame of analysis (see Table 13 below). VOCs are air pollutants that contribute to the formation of ground level ozone and particulate matter (PM2.5), which are the main constituents of smog. Exposure to smog is linked to adverse health impacts, including increased risk of premature death, chronic and short-term respiratory and cardiac problems, as well as negative environmental effects on vegetation, buildings and visibility.

Table 13: Estimated VOC reductions by standards (in kt)

Standard

2018–2025

2026–2030

2031–2035

Total

Facility production venting requirements

143

211

204

558

Leak detection and repairs

34

29

28

91

Well completion involving hydraulic fracturing requirements

4

2

2

8

Pneumatic controllers and pumps

24

33

33

90

Compressors

9

9

10

28

Total VOC reductions

213

284

276

773

Note: Numbers may not add up due to rounding.

A scenario analysis was conducted by the Department and Health Canada to evaluate the potential health and environmental benefits of changes in primary emissions of air pollutants expected to result from the Regulations. This analysis was based on preliminary modelling of VOC reductions completed in 2016. The table below outlines the emission results from the 2016 modelled case compared to the expected reductions in the final analysis, for which air quality modelling was not completed. As the 2016 modelled case resulted in less VOC reductions than the final results, this scenario likely underestimates the air quality benefits attributable to the Regulations.

Table 14: Estimated VOC reductions by scenario (in kt)

National VOC Reductions

2016 Preliminary (modeled)

2017 Final (not modelled)

VOC Reductions in 2025

48

57

VOC Reductions in 2035

51

54

The estimated VOC reductions were used as inputs and applied to the baseline emissions in 2025 and 2035 within A Unified Regional Air-Quality Modelling System (AURAMS). AURAMS was then used by the Department to estimate the impacts on ambient air quality resulting from the interaction of changes in methane emissions with existing ambient air quality, daily weather and wind patterns.

Health and environmental benefits

Health Canada applied the Air Quality Benefits Assessment Tool (AQBAT) to estimate the health and economic impacts associated with the air quality projections generated by AURAMS for 2025 and 2035. The modelled changes in ambient air quality levels were allocated to each Canadian census division and used as inputs for AQBAT. Based on changes in local ambient air quality, AQBAT estimated the likely reductions in average per capita risks for a range of health impacts known to be associated with air pollution exposure. These changes in per capita health risks were then multiplied by the affected populations in order to estimate the reduction in the number of adverse health outcomes across the Canadian population. AQBAT also applied economic values drawn from the available literature to estimate the average per capita economic benefits of lowered health risks.

Similarly, air quality modelling results for 2025 and 2035 from AURAMS were used as an input for the Air Quality Valuation Model 2 (AQVM2) to model environmental impacts. Air pollutants such as VOCs are precursors to the formation of secondary particulate matter and ground-level ozone, which impact air quality and the environment by damaging forest ecosystems, crops and wildlife. Smog and deposition of suspended particles may impair visibility and result in the soiling of surfaces, respectively, thereby reducing the welfare of residents and recreationists, and potentially increasing cleaning expenditures.

Monetized health and environmental benefits have been derived over the period of full implementation, from 2023-2035. Modelled results for 2025 and 2035 were assumed to extend in linear trends over this period. Over the time frame considered, health and environmental benefits attributable to changes in air quality resulting from the Regulations are estimated to be $240 million. The majority of these projected benefits are a result of estimated reductions in the risk of premature death multiplied by an estimate of the average willingness-to-pay for small reductions in the risk of premature death.

Table 15: Summary of Health and Environmental Benefits (in millions) based on 2016 modelling results

Monetized benefits (millions of dollars)

2025

2035

Total (2023–2035)

Air quality benefits

17

18

240

Note: Monetary values discounted to present value using a 3% discount rate.

Conserved gas

Methane is the primary component in natural gas, which can be used as a source of energy for heating, cooking, and electricity generation. Technical and process changes required by the Regulations will limit methane venting, reduce fugitive emissions, and thus lead to the conservation of approximately 351 PJ of natural gas (see Table 16).footnote47

Table 16: Estimation of conserved gas by standard (in PJ)

Standard

2018–2025

2026–2030

2031–2035

Total

Facility production venting requirements

8

14

13

35

Leak detection and repairs

43

36

35

115

Well completion involving hydraulic fracturing requirements

0

0

0

0

Pneumatic controllers and pumps

44

63

63

170

Compressors

10

11

11

31

Total conserved gas

105

123

122

351

Note: Numbers may not add up due to rounding.

The Regulations will lead to two opposing effects on total marketable gas production. First, compliance costs imposed by the Regulations are expected to lead to some premature well abandonment and foregone drilling, which will reduce production. Second, methane captured which would have otherwise been lost increases production. It is expected that the lost production from these shut-in wells would lead to a decrease in net exports of natural gas (and other fuels).footnote48 Recovered gas resulting from compliance with the Regulations would be expected to offset some of this decrease in net exports resulting from this lost production. Compliance costs are assumed to be incurred for some facilities and components that will be shut-in to avoid these costs, in lieu of a direct value of this lost production. Additionally, the costs associated with recovering this gas have been accounted for in this analysis. Thus, it is appropriate to use the market price net of transportation costs of natural gas to value this conserved resource. The conservation value of VOCs has not been quantified due to the relatively small quantities and the variability of hydrocarbon make-up of these VOCs.

A reference price for natural gas, which adjusts the market price to account for transportation costs, was used to estimate society’s willingness to pay for this conserved gas. Alberta Energy Regulator estimates of the Alberta Reference Price (ARP) were used, ranging from $3.04/GJ in 2018 to $4.45/GJ in 2035.footnote49 These prices were then applied to the estimated quantity of methane that will be conserved. The value of conserved gas as a result of the Regulations is estimated to be $1.0 billion over the time frame of the analysis (see Table 17).footnote50

Table 17: Total present value of conserved gas (millions of dollars)

Standard

2018–2025

2026–2030

2031–2035

Total

Facility production venting requirements

25

42

35

102

Leak detection and repairs

129

112

97

337

Well completion involving hydraulic fracturing requirements

0

0

0

0

Pneumatic controllers and pumps

134

192

173

500

Compressors

30

32

30

92

Total value of conserved gas

318

378

335

1,031

Note: Numbers may not add up due to rounding. Monetized values are discounted to present value using a 3% discount rate. It is assumed conservation of this gas will not lead to incremental combustion emissions. A sensitivity analysis below examines the potential impact if combustion of this gas leads to incremental emissions.

Summary of benefits and costs

By 2035, the Regulations are estimated to result in cumulative net GHG emission reductions of 232 Mt, valued at about $11.6 billion, cumulative gas conserved of 351 PJ, valued at about $1.0 billion, and 773 kt of VOC emission reductions valued at $240 million. The total benefits of the Regulations are valued at about $12.9 billion. The Regulations will also result in costs to industry and government of $3.9 billion. The net benefits of the Regulations to Canadians are $8.9 billion. These costs and benefits associated with the Regulations are summarized in Table 18.

Table 18: Summary of benefits and costs

Monetized Impacts (millions of dollars)

2018–2025

2026–2030

2031–2035

Total

Climate change benefits

3,396

4,148

4,044

11,588

Health and environmental benefits

58

90

92

240

Value of conserved gas

318

378

335

1,031

Total benefits

3,772

4,616

4,471

12,859

Industry compliance costs

2,405

780

685

3,870

Industry administrative costs

18

13

11

42

Government administrative costs

4

2

1

7

Total costs

2,427

794

697

3,918

Net benefits

1,345

3,822

3,774

8,940

Quantified benefits

Net GHG reduction (Mt CO2e)

67

83

82

232

VOC reduction (kt)

213

284

276

773

Gas conserved (PJ)

105

123

122

351

Note: Numbers may not add up due to rounding. Monetized values are discounted to present value using a 3% discount rate.

Cost per tonne of GHG emission reductions (2018–2030)

The Regulations are expected to achieve a net 150 Mt CO2e cumulative reduction in GHG emission reductions by 2030, which will contribute to addressing Canada’s international commitments, including the 2015 Paris Agreement. To achieve these GHG emission reductions, it is expected that compliance costs of $3.2 billion will be incurred between 2018 and 2030. However, conserved gas valued at $700 million over the same time frame is also expected. Overall, as indicated in Table 19, the anticipated GHG emission reductions will be achieved at an estimated cost per tonne of $21, and a net cost per tonne of about $17.

Table 19: Cost per tonne of GHG emission reductions (2018–2030)

Standard

Costs
(millions of dollars)

Value of conserved gas (millions of dollars)

GHG Emission Reductions
(Mt CO2e)

Cost per Tonne ($/t CO2e)

Net Cost per Tonne

($/t CO2e)

Leak detection and repairs

905

241

36

25

19

Compressors

186

62

9

20

13

Well completion involving hydraulic fracturing requirements

85

0

3

28

28

Facility production venting requirements

1,051

67

54

19

18

Pneumatic controllers and pumps

957

326

48

20

13

Total

3,185

696

150

21

17

Note: Monetized values are discounted to present value using a 3% discount rate.

These costs per tonne results reflect expected compliance costs and conserved gas savings to reduce tonnes of GHG emissions from methane. These results do not account for when emission reductions occur, or for the value society may place on the avoided damages.

Distributional analysis of regulatory impacts

This summary presents the benefits and costs to Canadian society as whole. These impacts are not uniformly distributed across society so the analysis has considered a range of distributional impacts.

Impacts by region

The compliance costs associated with the Regulations will vary by region. The production of oil and gas is mainly concentrated in the provinces of British Columbia (B.C.), Alberta (Alta.), and Saskatchewan (Sask.). Table 20 shows the breakdown of overall costs, emission reductions, and conserved gas attributable to the Regulations across Canadian regions. Due to the concentration of oil and gas activities in the Western provinces, the majority of impacts are expected in British Columbia, Alberta, and Saskatchewan with the remainder distributed throughout the rest of Canada (ROC).

Table 20: Distribution of quantified benefits and monetized costs across regions

Category

B.C.

Alta.

Sask.

ROC

Total

Reduced net GHG emissions (Mt CO2e)

22

122

86

2

232

Gas conserved (PJ)

46

232

67

5

351

Reduced VOC emissions (kt)

50

400

315

8

773

Compliance costs (million $)

348

2,190

1,289

42

3,870

Note: Numbers may not add up due to rounding. Monetized values are discounted to present value using a 3% discount rate. The benefits of quantified reductions and conserved gas displayed in the table do not necessarily accrue to the corresponding province.

Impacts by sub-sector

The compliance costs associated with the Regulations will also vary by sub-sector within the oil and gas industry. Table 21 shows the breakdown of overall costs and benefits of the Regulations across oil and gas products. Due to the large number of facilities affected, the natural gas production and processing sector is expected to incur the largest cumulative costs and attributed emission reductions over the period of analysis.

Table 21: Distribution of quantified benefits and monetized costs across sub-sectors

Category

Light Oil Mining

Heavy Oil Mining

Natural Gas Production

Natural Gas Processing

Natural Gas Transmission

Total

Reduced net GHG emissions
(Mt CO2e)

58

63

80

27

2

232

Gas conserved (PJ)

77

29

179

60

5

351

Reduced VOC emissions (kt)

590

36

84

58

5

773

Compliance costs (million $)

1,153

581

1,420

663

52

3,870

Note: Numbers may not add up due to rounding. Monetized values are discounted to present value using a 3% discount rate. The benefits of quantified emission reductions and conserved gas displayed in the table do not necessarily accrue to the corresponding sub-sector.

Consumer impacts

Given that crude oil and natural gas are commodities which are priced in global and continental markets, the Regulations are not expected to have impacts on the price of these products. Therefore, the Regulations are not expected to have impacts on consumers.

Competitiveness impacts

The Regulations will impose compliance costs on oil and gas companies, which will divert resources from other productive uses. The impacts of the costs of regulatory compliance will likely be greater for firms with constrained access to capital, such as smaller oil and gas producers with lower levels of production.

The Department anticipates that the impact of the Regulations will likely be small for producers of light oil and natural gas. Heavy oil producers are expected to experience slightly larger financial impact as a result of the Regulations, because compliance costs represent a larger proportion of their current development costs relative to natural gas and light oil wells. This results in a greater proportional impact on profitability for heavy oil wells.

Total undiscounted compliance costs are estimated to be $4.96 billion over the period of analysis. In 2016, total capital and operating expenditures, excluding royalty payments, in the Western Canadian conventional oil and gas sector were $33.5 billion, the lowest level since 2003 and 31% lower than the average annual expenditures over the previous 10 years. If spending in the sector remained at these comparatively low levels over the time frame of analysis, the compliance costs from the Regulations would represent less than 0.8% of cumulative industry expenditures ($603.8 billion) over the 18-year period.

For existing facilities, the costs of compliance can represent large one-time expenses. Some investments could be influenced at the margin and these costs could affect the viability of some existing facilities with lower production levels if they do not have sufficient time remaining in the facility’s life to recover the compliance costs. In certain cases, existing facilities may cease production earlier than they otherwise would have in the absence of the Regulations.

In response to the potential financial and competitiveness impacts of the Regulations, several flexibilities have been included. For example, standards that will require significant capital investment, such as the facility production venting requirements and the pneumatic controller and pump requirements will not come into force until 2023, giving firms lead time to adjust. The Regulations will also allow facilities that experience technical or economic challenges from complying with the standard for pneumatic pumps to apply for a time-limited exemption permit. Further, the Department has made modifications to the Regulations from those proposed in CG-I which reduce compliance costs by an estimated $500 million over the period of analysis.

There will be a general alignment with U.S. measures when the Regulations come into effect for both new and existing facilities in 2020 and 2023, based on U.S. requirements currently in place. Since 2012, the U.S. EPA has been regulating tank venting, well completions involving hydraulic fracturing operations, low vent pneumatic devices, compressor venting and fugitive emissions from new onshore oil and gas facilities. Given the annual investments made to both maintain and increase crude oil and natural gas production, these requirements are expected to apply to most existing U.S. facilities by 2023. The emission sources covered by both regulatory regimes are generally aligned. Additionally, almost all U.S. oil and gas production is subject to more general state-level venting requirements, with some states, such as Pennsylvania, California, and Colorado, taking additional actions to manage fugitive emissions.

Distribution of climate change benefits

The Social Cost of Carbon and Social Cost of Methane are measures of the incremental avoided global damages from a decrease in CO2 or CH4 emissions. Therefore, the climate change benefits attributable to the Regulations, estimated at $11.6 billion, will be distributed globally. There are two unique aspects to climate change that justify the use of global values to value the benefit of GHG reductions: (1) it involves a global externality, where emissions anywhere in the world contribute to global damages; and (2) the only way to effectively address climate change is through global action. Therefore, the Department has concluded that the most credible approach to estimating the social cost of greenhouse gases is on a global scale.

Uncertainty of impact estimates

The results of this analysis are based on key parameter estimates, which may be higher or lower than indicated by available evidence. Given this uncertainty, sensitivity analyses were conducted to assess the impact of changes to these parameters on the expected net benefits of the Regulations, where possible.

Compliance costs: The estimated costs of compliance may be higher or lower than estimated in the central analysis. Feedback from stakeholders was solicited by the Department, which yielded a range of results. Additionally, it is expected that future technological advances in leak detection technology could result in significantly lower costs. To estimate the effect on the final results of different cost estimates, sensitivity analyses were conducted for two scenarios; a low cost scenario which assumes the lower range of costs, including adoption of new LDAR technology such as aerial leak detection methods, or low-cost sensors (25% uptake in 2021 increasing to 100% in 2030); and a high cost scenario which assumes an upper bound on costs, both based on information received through consultation with stakeholders. These two scenarios estimate the costs of the Regulations could vary between a range of $2.3 billion and $5.8 billion.

Baseline emissions estimates: Recent studies which measured methane emissions from the oil and gas sector have found that fugitive and venting emissions may be significantly greater than current estimates. The central analysis first estimates emissions using an engineering model, and then scales these estimates to the departmental baseline. As the engineering model estimates significantly higher baseline emissions than the departmental baseline, an analysis of the results without scaling emissions was conducted to determine the impact of greater emissions on the overall results. Costs in this scenario are unchanged, as they were not scaled in the central analysis. This alternate scenario results in benefits equal to $21.9 billion, with 31 Mt of emission reductions in 2025.

Downstream combustion of conserved gas: There is some uncertainty regarding the degree to which conserved gas will lead to incremental downstream consumption of natural gas and, therefore, increased GHG emissions. The central analysis assumes that the Regulations do not materially impact consumption of natural gas and, therefore, CO2 emissions from downstream combustion of conserved gas is not considered. However, it is possible that Canadian production is exported and incremental consumption of natural gas is altered in a way leading to increased combustion, at the expense of alternative forms of energy. This could lead to an increase in CO2 emissions, depending on the energy source this natural gas displaces. To determine an upper bound on the potential CO2 emissions that could occur from increased consumption of conserved gas as a result of the Regulations, a sensitivity analysis was conducted, which assumed all conserved gas represents incremental consumption and, therefore, combustion emissions would increase. This alternate scenario results in expected net benefits of about $8.2 billion, with 15 Mt of CO2e emission reductions in 2025 compared to 16.4 Mt in the central analysis.footnote51

Oil and gas production and price forecasts: Oil and natural gas production is strongly correlated with oil and gas prices which are highly volatile and largely determined by external commodity markets. As future emissions are strongly correlated with future production, this price volatility leads to uncertainty in the estimates of the impacts of the Regulations. To assess the potential impact on the results of the analysis variation in future production and prices may have, a high price and low price scenario were assessed per the National Energy Board’s high and low forecast scenarios. Variation in production and price forecasts results in roughly proportionate changes in costs and benefits (see Table 22 below).

Benefits valuation: The values used to determine the benefits of the Regulations are also subject to uncertainty. The SCC and SCCH4 used to value future climate benefits are generated using models which rely on forecasts of both natural and economic outcomes 50 to 300 years into the future, making these estimates inherently uncertain. Additionally, the prices used to value conserved gas may overvalue society’s willingness to pay for this conserved resource. To evaluate the impact of potential differences in the true values of these variables compared to the estimated values, a sensitivity analysis was conducted where the value of the benefits attributed to the Regulations are 50% lower than the central case. This scenario still yields an expected net benefit of $2.5 billion.

Discount rate: TBS recommends a 7% discount rate for cost-benefit analyses in most cases; however, when a regulation has impacts occurring over a long time horizon, a lower discount rate (3%) is appropriate. A sensitivity analysis was done to compare the central case (3%) to the higher discount rate (7%), which still yields an expected net benefit, as shown in Table 22.

A worst-case scenario was also considered in which oil and gas prices are low, compliance costs are high, benefits are valued at 50% of the central case, and all conserved gas leads to incremental combustion emissions. In this unlikely case, the Regulations still yield a net benefit of $77 million. Therefore, the results are robust in terms of demonstrating positive net benefits for the Regulations across a broad range of plausible values for key variables.

Table 22: Sensitivity analyses (millions of dollars)

Variable(s)

Sensitivity Case

Benefits
(B)

Costs
(C)

Net Benefits
(B – C)

Net Cost per Tonne (2018–2030)

Central case (from Table 11)

  

12,859

3,918

8,940

17

Compliance costs

High

12,859

5,758

7,100

26

Low

12,859

2,341

10,517

9

Oil and gas prices/production

High

14,744

4,015

10,730

12

Low

10,409

3,291

7,118

18

Baseline methane emissions

Unscaled

25,829

3,918

21,911

6

Downstream combustion of conserved gas

100% downstream combustion

12,077

3,918

8,159

18

Benefits Valuation

50% of central case

6,429

3,918

2,511

17

Discount rate

7%

8,453

2,879

5,575

13

Costs

Prices

Benefits

Downstream combustion

Costs — High

Prices — Low

Benefits — 50%

Combustion — 100%

4,864

4,787

77

30

Note: Values discounted to present value using a 3% discount rate, except in the case in which a 7% rate is used.

It is assumed that the impacts (benefits and costs) occur because regulatees will not change their behaviour in the absence of the Regulations. There would likely be some natural adoption of lower-emitting equipment or practice without the Regulations. If an alternate baseline scenario had been proposed whereby more regulatees would have chosen these GHG reduction strategies voluntarily, then the estimated costs and benefits attributable to the Regulations would be proportionally lower, which would still yield an expected net benefit.

“One-for-One” Rule

The Regulations are considered an “IN” under the Government of Canada’s “One-for-One” Rule. The total annualized administrative costs for the regulatees to comply with the regulatory requirements over a 10-year time frame are estimated to be approximately $1.8 million for all stakeholders, or $1,900 per company.footnote52 In addition, the Regulations will be a new regulatory title (IN), which must be offset by the repeal of an existing regulation (OUT) under the Government of Canada’s “One-for-One” Rule.

The main driver (78%) of administrative costs is record keeping (the Regulations will require facilities to keep records of compliance). It is assumed that some of the data needed to comply with this requirement is already accessible and kept by the regulatees in British Columbia, Alberta and Saskatchewan due to existing provincial requirements. Consequently, the additional information that is required is primarily the record keeping of emissions of methane from the facility and the occurrences of leaks. This is estimated to range from 15 minutes to 40 hours per company per year depending on the standard.footnote53

The other main driver (17%) of administrative costs is operator registration requirements. For each facility, regulatees will be required to register and send a one-time registration report to the Minister. Based on the data used for recently published regulations affecting the oil and gas sector, it is assumed that it takes 1.5 hours to register each facility and 2 hours per company to prepare and submit the information.footnote54

Comments received from stakeholders following publication of the proposed Regulations challenged the amount of time estimated to complete administrative activities. One industry association questioned the total time per facility estimated to complete administrative requirements. A technology industry association suggested that registration requirements would take significantly longer to complete than estimated by the Department. In response to these comments, the Department has reduced the registration requirements by simplifying the requested information. The Department has revised its analysis to reflect updates to record-keeping requirements. Additionally, the estimated time to complete some administrative tasks was revised upward.

Small business lens

It is estimated that the Regulations will affect approximately 41 400 oil and gas facilities currently in operation, owned by 929 companies. Although the majority of facilities that will be covered by the Regulations are owned by medium and large businesses, some facilities operated by small businesses will also be covered. Therefore, the Regulations will trigger the small business lens. An estimated 1 926 of these facilities are owned by 540 small businesses.

To reduce costs associated with the Regulations, small businesses facilities operating with a potential to emit (PTE) under the 60 000 m3 threshold will be exempt from the facility venting, pneumatics, and LDAR requirements under the Regulations (flexible option).

A large number of small businesses own facilities that emit gaseous hydrocarbons below the threshold, thus they will not be subject to the above-mentioned requirements, nor the associated record keeping and on-demand reporting requirements. The Regulations are expected to exempt approximately 55% of small businesses. The Regulatory Flexibility Analysis Statement below (Table 23) shows the expected costs to small businesses under the initial and flexible options.footnote55

Table 23: Regulatory Flexibility Analysis Statement

 

Initial Option
(standards without a 60 000 m3 PTE threshold)

Flexible Option
(standards with a 60 000 m3 PTE threshold)

Number of small businesses impacted

540

540
 

Annualized Value*

Present Value

Annualized Value*

Present Value

Compliance costs

$6,866,000

$90,403,000

$2,119,000

$27,896,000

Administrative costs

$249,000

$3,274,000

$164,000

$2,162,000

Total costs

$7,115,000

$93,677,000

$2,283,000

$30,058,000

Average cost per small business

$13,000

$165,000

$4,000

$53,000

Risk considerations:

The initial option will cover all facilities, including small facilities which, in total, account for a small portion of the emissions. The initial option will impose a higher cost (relative to production/revenues) on smaller facilities than on larger facilities.

In the upstream oil and gas sector, it is typical for a small business to be operating facilities that fall under the threshold for application in the flexible option. These facilities do not represent a significant portion of the total emissions. The Regulations cover the majority of emissions, while providing flexibility for small businesses.

Overall, the flexible option results in an estimated reduction of total costs per small business of approximately $112,000 between 2018 and 2035, relative to the initial option under consideration, or approximately $9,000 per year. The Regulations will result in cumulative costs of approximately $30 million for small businesses, or $53,000 per small business. While not part of this assessment, the design elements of the flexible option are expected to reduce administrative and compliance costs for large businesses that own smaller facilities.

Feedback received from small businesses regarding the proposed Regulations

Feedback on the proposed Regulations was received from small businesses through the Explorers and Producers Association of Canada (EPAC), which represents 135 small and mid-sized oil and gas companies headquartered in Canada. Generally, EPAC expressed its support for the Government of Canada’s target for reducing methane emissions. They were however concerned with the practicality, costs and timing of implementation of the Regulations amid the current economic context of the oil and gas sector and increased competitiveness concerns. EPAC requested the potential to emit threshold be increased to avoid disproportionate impacts to small business. Additionally, they requested the venting limit be increased to allow small, mature facilities to avoid uneconomic costs to install vapour recovery equipment on storage tanks. Requests were also made to reduce leak detection frequency and eliminate pneumatic pump requirements. In addition to EPAC’s comments, the Department also received comments from a small producer whom expressed concerns with the stringency of the venting requirement.

To address these concerns, the Department raised the venting limit from 3 000 m3 to 15 000 m3 per year. In addition, the potential to emit calculation was amended to include the past 12 months, as opposed to largest 12 consecutive months in the previous 60 months. These changes will exempt smaller, more mature facilities. Further analysis and response to concerns raised by these commenters can be found in the Consultation section below.

Consultation

Consultations prior to the publication of the proposed Regulations in the Canada Gazette, Part I (CG-I)

Prior to publication of the proposed Regulations, the Department held over 150 hours of consultations with stakeholders and provincial partners, including webinars, teleconferences, face-to-face meetings, technical discussions and bilateral meetings. Representatives from industry, provinces, territories, environmental non-governmental organizations (ENGOs) and associations representing Indigenous Peoples participated.

In response to industry and provincial government comments, the Department amended the coming-into-force dates of the draft Regulations to 2020 for LDAR, compressors and well completion involving hydraulic fracturing requirements, and to 2023 for facility production venting and pneumatic device requirements. In addition, the draft Regulations were amended to require leak inspections three times per year, as opposed to four, to account for operational difficulties in the winter. The emission limit for reciprocating compressors was increased to reduce compliance costs. Finally, the control measures for well completion involving hydraulic fracturing were removed for the jurisdictions of British Columbia and Alberta due to the existing provincial measures that cover these activities.

In response to ENGO comments, the Department changed the compliance limit for the facility venting limit of the proposed Regulations to remove the percent reduction flexibility, replacing it with an absolute standard of 3 000 m3 in the previous twelve months. The threshold for application of pneumatic pump control measures was decreased to cover more of these devices and achieve more emission reductions. A mandatory capture and conserve rule was introduced for all new compressor installations. The Department included extensive record-keeping requirements in the proposed Regulations and would be able to require reporting when needed, addressing concerns regarding enforceability.

Feedback received during the 60-day public comment period following publication in CG-I and modifications made for final Regulations

The publication of the proposed Regulations on May 27, 2017, initiated a 60-day public comment period where interested parties were invited to submit their written comments. The proposed Regulations were posted on the Department’s CEPA Environmental Registry website to make them broadly available to interested parties. The Department also emailed interested parties to inform them of the public comment period. The Department received 52 written submissions from a range of stakeholders, including oil and gas industry and industry associations, ENGOs, provinces and municipalities, clean technology companies, and an Indigenous organization.

Overview of feedback received

Generally, oil and gas industry stakeholders continue to support the environmental objective of the Regulations and the Government of Canada’s methane emissions reductions target. However, they expressed a need for more flexibility in achieving the targeted reductions, concerns with the stringency of the requirements, their administrative burden and the potential impacts on competitiveness of the Canadian oil and gas sector. They also requested improvements to the current national greenhouse gas inventories to better reflect current emissions reporting. Clean technology providers stressed the importance of allowing oil and gas companies the flexibility to use innovative technologies to meet the requirements of the Regulations.

ENGOs remain supportive of the Regulations; however, they indicated greater coverage and more stringent requirements are needed. They also requested that the Government of Canada increase the level of accountability and mandate direct measurement in the place of estimation of emissions. Academic researchers largely echoed comments and recommendations made by ENGOs and provided new data on oil and gas methane emissions that revealed higher emissions than what is currently reported. One Indigenous organization provided similar comments and recommendations made by ENGOs.

Some provincial governments and municipalities also commented on the proposed Regulations. Provincial comments largely echoed industry’s concerns, specifically citing issues surrounding competitiveness, the need for flexibility in approach, and improvements to the current national greenhouse gas inventories to better reflect current emissions reporting. Specific feedback was also provided on the coverage of the proposed Regulations and the stringency of specific requirements. Provinces with offshore operations noted that methane requirements for the offshore oil and gas sector should not be addressed in the Regulations, citing the Accord Acts and their regulations as the appropriate body to regulate Canadian offshore oil and gas operations. Municipalities primarily highlighted their concerns regarding the potential for negative economic impacts in regulating the oil and gas sector.

Feedback was also received regarding the assumptions and cost estimates in the Costs and Benefits section of the Regulatory Impact Analysis Statement (RIAS). In response to this feedback, the Department consulted with stakeholders to ensure a clear understanding of the appropriate modelling assumptions and parameters used in the analysis. Updates and clarifications on information related to compliance costs, baseline methane emissions estimates, and attribution of independent industry action are included in the final version of the RIAS in response to stakeholder concerns.

Overview of modifications made to the Regulations

The Department amended aspects of the proposed Regulations in response to in-depth analysis of stakeholder feedback and subsequent extensive stakeholder engagement. These changes primarily consist of modifications to specific requirements and do not represent broad changes to the stringency of the Regulations. The changes address specific technical compliance challenges raised by industry stakeholders, provide additional compliance flexibility, reduce administrative burden and compliance costs, and optimize methane emission reductions through fewer requirements. These changes are summarized in the Description section above, with a more in-depth discussion for each source below.

Overall, the changes to the Regulations reduce the expected methane reductions (in CO2 equivalent) attributable to the Regulations by 0.98 Mt in 2025, compared to the reductions anticipated in the proposed Regulations. The Government of Canada is still able to meet its methane reduction target of 40–45% from 2012 level by 2025 from the oil and gas sector as a result of the Regulations. Compliance costs have been reduced by approximately $500 million over the period of analysis as a result of these changes.

Analysis and responses to specific stakeholder feedback received

The Department conducted an analysis of all the stakeholder feedback and in several cases made adjustments to elements of the Regulations. This analysis is presented below along with a description of the changes that were incorporated into the final Regulations.

Venting
Venting Limit

Industry stakeholders proposed a 250 m3 per day facility venting limit, compared to the proposed Regulations limit of 250 m3 per month. This proposed limit would include all vented emissions, including pneumatics and compressors. Additionally, they suggested a fleet average for cold heavy oil production with sand (CHOPS) facilities. ENGOs recommended strengthening the venting requirements.

The Department has increased the venting limit from 250 m3 per month to 1 250 m3 per month in the final Regulations to address industry’s concerns. In many cases, safely mitigating tank venting, particularly at low vented volumes, requires significant capital investment relative to the achieved emission reductions. This higher limit, while not as high as the limit proposed by industry stakeholders, will allow many medium to smaller crude oil facilities to continue venting from storage tanks without requiring venting controls on these tanks, as long as other venting sources at that facility are controlled sufficiently to meet the venting limit.

A facility venting limit which includes pneumatic and compressor equipment emissions was considered by the Department; however, it was not considered viable due to the wide variability in the design and use of these individual pieces of equipment across all oil and gas facility types. In contrast, the Regulations will mandate separate equipment standards that ensure more predictable management of intentional routine venting of waste gas across sites with varying equipment usage.

Regarding industry’s request to use a fleet average approach, the standard suggested by industry would not result in the required contribution from this sector to meet the regulatory objectives. Further, given that the vented emissions vary significantly over time at facilities and across the population of facilities, there is no singular standard that could be applied at the fleet level to achieve ongoing specific emission reductions. Such an approach would require periodic amendments that would contribute to on-going uncertainty and administrative burden.

Exemptions

Several oil and gas companies have requested full or partial exemptions from the proposed venting limit for thermal in-situ oil sands facilities and natural gas transmission and storage facilities, or to be regulated to a 95% annualized conservation requirement instead of a vent limit. Additionally, industry stakeholders requested an exemption for storage tanks.

The Department agrees that certain facility configurations would have difficulty complying with the proposed venting limit. Some of these compliance challenges are expected to be alleviated by increasing the venting limit from 250 m3 to 1 250 m3 per month. In addition, the Department also clarified the emission sources that shall be excluded in the venting limit, including venting sources already covered in other sections of the Regulations. With the revised venting limit of 1 250 m3 per month, many medium to smaller crude oil facilities will now be able to continue uncontrolled venting from storage tanks without exceeding the vent limit, as long as other venting sources at a facility are adequately controlled.

Potential to emit and surplus gas thresholds

Industry stakeholders raised concerns regarding the proposed PTE threshold of 60 000 m3 per year for triggering application of some requirements, including venting. Additionally, industry suggested the PTE threshold be either removed or based on the previous 12 months or a three month rolling average.

ENGOs expressed concern with the under-reporting of vented emissions and proposed to allow the use of a PTE threshold only for facilities, which directly measure their vented gas volumes, and to remove the PTE threshold exemption for facilities which estimate, instead of directly measure, their gas volumes.

One academic suggested the Department include fuel volumes in the surplus gas (SG) threshold calculation to ensure vented gas volumes are not incorrectly reported as fuel use. Another suggestion was to include all vented volumes at sites (including pneumatics, compressors, etc.) in the SG threshold calculation. It was also suggested to eliminate the SG threshold and use only the PTE threshold to trigger venting reduction requirements. Many commenters from both industry and ENGOs requested clarity on the purpose of these thresholds and how they should be calculated and utilized.

The Department’s view is that inclusion of both of the thresholds remains a valid approach to ensure vented emissions are reduced in a cost-effective manner and their proper utilization should continue in the determination of venting requirements, but agrees that reducing the PTE timeline from five years to the previous calendar year is appropriate. To enhance clarification of the intent and utilization of these two thresholds, the Department will include a detailed description of each in a separate regulatory compliance guidance document.

Gas estimation accuracy

Industry stakeholders expressed concerns with requirements stating that all heavy oil facilities must directly measure all gas streams over 500 m3 per day, instead of the current direct measurement rate threshold of 2 000 m3 per day required by provincial authorities.

ENGOs recommended that operators should directly measure, rather than estimate, the total facility gas production (including all gas as fuel, sales, vented casing gas and all tank vent gas) at all conventional heavy oil production facilities. If direct measurement is not required, ENGOs recommended that the operator should conduct a seven-day test to determine the well’s gas-to-oil ratio (GOR). Current provincial measures require a GOR test period of only 24 hours.

As a result of these concerns, the Department has introduced flexibility and increased accuracy through modifying the gas estimation requirements at heavy oil facilities. Three gas measurement/estimation options have been added: direct measurement of the gas stream, the use of a more rigorous GOR estimation protocol, or the use of a pre-assigned GOR algorithm to determine facility produced gas.

Leak detection and repair
Scope of coverage of the oil and gas sector

The Department received many comments from industry stakeholders regarding the types of installations that should be covered by the LDAR requirements. The transmission pipeline sector conveyed concerns with performing inspections and repairs at numerous remote locations which are difficult to access and suggested that small remote compressor stations, valve stations, and metering stations on transmission pipelines be exempted from LDAR requirements. The upstream production sector stated that the proposed exemption for facilities consisting of a single wellhead should be extended to those facilities that have single wellheads with metering runs. An industry association stated that large oil and gas facilities that are already subject to conditions under Alberta’s Environmental Protection and Enhancement Act (EPEA) should be excluded from the LDAR requirements. One ENGO requested that LDAR inspections be required for all abandoned wells.

The Department’s analysis shows that extending the exemption for single wellheads to situations where there is gas metering equipment alongside would reduce compliance costs and not have a significant impact on emissions reductions. Similarly, the exemption of valve stations, consisting uniquely of shutdown valves, on transmission pipelines is expected to result in a decrease in inspection costs with minimal loss in emission reductions. Consequently, these installations have been exempted from the leak detection requirements.

Metering stations and small compressor stations may consist of a large quantity of surface equipment that have the potential for leakage, including compressors, heaters, pressure reducers, regulators and condensate storage tanks. The Department’s analysis demonstrates that metering stations and small compressor stations are significant sources of methane emissions. For this reason, metering stations and small compressor stations will not be exempted from LDAR requirements.

EPEA conditions are applied on a case-by-case basis, while the Regulations require periodic inspections for all facility types, setting a standard for inspection frequency that is consistent for all facility types. Therefore, facilities in Alberta that are already subject to EPEA approvals will not be exempted from LDAR requirements.

Regarding abandoned wells, the Department notes that these wells can still emit hydrocarbons. Thus, they would be considered covered equipment subject to LDAR requirements if they exist at a site where production and receipts of gas exceed the potential to emit the threshold of 60 000 m3 per year.

Allowed instruments for inspection and overall design of LDAR approach

Industry stakeholders strongly expressed a need to consider additional flexibilities in the inspection requirements by allowing alternative inspection methods to include continuous monitoring and more frequent lower sensitivity surveys, such as using aerial, satellite, or mobile vehicle surveys. Many commenters noted that the leak detection instrument approval process described in the proposed Regulations is onerous and does not enable adoption of innovative technology. Other commenters requested that the wording be changed to allow for equivalent outcomes rather than equivalent technology.

The Department agrees that alternative inspection methods should be an option when equivalent emission reductions are demonstrated as there are significant potential future developments in leak detection that could reduce LDAR costs. The Department introduced modified language to allow regulatees to demonstrably prove that any alternate method is capable of producing equivalent outcomes to those described in the regulatory requirements.

Coverage of components

Industry advised that there are specific types of equipment components that should be subject to LDAR requirements. Some commenters requested that inaccessible components (e.g. equipment components which may be difficult to safely reach with a portable monitoring instrument) be exempted. ENGOs requested that equipment designed to vent be explicitly included in LDAR inspections.

To address these concerns, the Department revised the proposed Regulations to include certain flexibilities. Equipment components can now be exempted from LDAR inspection if the facility operator deems them “unsafe to inspect” with both a portable monitoring instrument and an OGI camera. However, OGI technology would enable imaging for most equipment components from various safe vantage points; therefore, there will be no exemption for inaccessible components.

As for including all equipment designed to vent, the Regulations contain other obligations that are intended to limit intentional venting from equipment sources such as pneumatics and compressors. Because some intentional vented emissions may be difficult to differentiate from unintentional leaks, the Regulations have been modified to specifically exclude intentionally vented emissions, where other venting limits apply to those emissions.

Inspection frequency and timing of inspections

Some industry commenters requested that inspection frequency be reduced, with a risk-based approach based on past performance of facilities or equipment types. ENGOs commented that inspections should be done quarterly, with monthly inspections at the largest facilities, to align with the programs used by leading states and companies in the United States.

The Department notes that historical LDAR performance is not a predictor of future performance as leaks are random unpredictable events. Thus, the Department did not adopt a risk-based approach. The Department’s analysis shows emission reductions attained with three inspections per year justify the cost of these inspections, while minimal emission reductions would be gained with significant costs if more frequent inspections were required.

Timelines for repairs of leaks

Comments received from Canada’s offshore boards and the offshore industry focused on the unique circumstances faced by offshore operators, specifically the difficulty in completing repairs to specialized equipment within the time limits outlined by the Regulations. The transmission sector requested that repairs be subject to a reasonable delay when the shutdown of transmission pipeline equipment is not feasible.

The Department adjusted the time limit for offshore repairs such that all repairs have a time limit of 730 days. To address concerns with the difficulty in completing repairs for specialized equipment under extenuating circumstances, the Regulations have been adapted to provide the Minister the authority to issue a renewable permit to grant extra time to onshore and offshore operators to complete repairs.

Pneumatics
Inclusion of pneumatic devices in venting limit

Industry stakeholders suggested including pneumatic devices in an overall venting limit and removing the pneumatic controller and the pneumatic pump specific requirements. ENGOs stated that emissions from these devices need to be included in the venting limit to ensure that they are accounted for and that the venting limit excludes facilities which are truly below the limit.

The Department will maintain the approach of regulating emissions from pneumatic controllers and pneumatic pumps. The Department’s view is that there is already sufficient flexibility for the operator to choose how to reduce emissions within the pneumatics requirements, including switching to electric devices or routing the emissions to a conservation or destruction device. This approach also does not require quantification of emissions from pneumatic devices which would be necessary if they were to be included in a venting limit, which would increase administrative burden.

Zero-emitting controllers

Industry recommended removing zero-emitting controller requirements for facilities that lack access to electricity. ENGOs suggested that this should be required at more facilities and identified other criteria which, in addition to the compressor rated power threshold, could be used to target larger facilities.

Analysis completed by the Department determined that the incremental benefit of requiring facilities to use zero-emitting controllers did not justify the significant incremental costs. Thus, the Department decided to remove the requirement for zero-emitting pneumatic controllers and instead require all controllers at facilities meeting the PTE threshold to be subject to the design bleed rate limit of 0.17 standard m3 per hour.

Controller emissions measurement

ENGOs recommended requiring measurement of the bleed rate for all controllers, as supported by studies showing that these devices often emit more than they are designed to emit. The Department acknowledges this is often the case when these devices are not operated according to the manufacturer’s specifications. The proposed Regulations required the device to be operated according to the settings specified by the manufacturer and the Department determined that, if operated appropriately, measurement of the emission rate is not necessary to demonstrate compliance.

It was also raised that the manufacturer’s operational specifications for these controllers are not always available or applicable for every controller, for example if they have been modified for a specific application. To ensure compliance in these cases, controllers without operational specifications will be required to demonstrate the bleed rate is below the limit which can be done by directly measuring the static bleed rate.

Pump threshold for quantity of liquid pumped

ENGOs expressed concern that the threshold of 20 L per day for a pump could be bypassed by using multiple smaller pumps instead of one larger pump. To ensure this unintended compliance pathway is not available, the threshold of 20 L per pump has been replaced with a 20 L threshold per site. This prevents multiple pumps from being used and will ensure the threshold is not exceeded.

Compressors
Fleet average alternative approach

Industry proposed using a fleet average limit for compressors to control and reduce compressor emissions instead of the requirement to meet flat limits as outlined in the proposed Regulations.

The Department’s analysis shows that leakage from compressor seals varies over time as operational parameters change, such as the compressor discharge pressure, and randomly as seals wear. To accurately quantify a fleet average, continuous emission monitoring would be required, as well as tracking the hours over which the compressor is pressurized. Due to the resultant administrative burden and increased costs associated with monitoring and information tracking, a fleet average approach was not considered to be a viable option.

General flexibilities

Industry stakeholders commented that new compressors should be defined as those that are installed on or after 2025, while ENGOs suggested that it should be 2019, as opposed to being defined as those installed on or after January 1, 2020. The Department’s analysis suggests that an earlier date would gain minimal emission reductions, while a later date would allow more time for emerging innovative technologies to be commercialized, potentially reducing operational costs due to longer-lasting or lower-leakage components. Based on discussions with compressor seal manufacturers, these new technologies are highly likely to be commercialized by 2023. As a result, the Department defined new compressors as those that are installed on or after January 1, 2023.

Industry stakeholders expressed concerns that it is not always possible to take corrective action within 30 days of measurement for reciprocating compressors and that corrective action should take place within 90 days, similar to the proposed centrifugal compressor requirements. The Department’s analysis shows that increasing the time period for reciprocating compressors has a minimal effect on emissions and increases feasibility for industry. Therefore, a change has been made to the Regulations where corrective action may now take place up to 90 days of measurement.

Industry recommended that continuous monitoring be an option to replace the need for annual emission measurements. As some compressors are already equipped with continuous monitoring devices, the Department agrees that allowing continuous monitoring to replace the annual measurement will reduce costs to industry at facilities where these devices are already installed, while meeting the measurement needs. The Department has therefore added the option to replace the annual measurement in the case that devices used for continuous monitoring have alarms set at the applicable regulatory limit.

Exemptions

Industry stakeholders stated that because dry seals are the industry standard, centrifugal compressors with dry seals should be exempt from the requirements. The Department recognizes that, while modern centrifugal compressors are equipped with dry seals, manufacturers of these seals have confirmed that dry seals still do fail; therefore, they will still be subject to the limits.

Industry stakeholders suggested including an exemption for small and low-use compressors, which include compressors that are used less than 5% of the time, small compressors that have a rated brake power of less than 75 kW, and compressors with fewer than four cylinders. The Department’s analysis demonstrates that compressors with fewer than four cylinders represent 17% of compressor methane emissions — a value that is considered too significant to exempt. However, compressors pressurized less than 5% of the time and those with a rated brake power less than 75 kW represent only 1% of emissions, having a minimal impact on emission reductions. Consequently, the Department has exempted compressors pressurized less than 5% of the time and those with a rated brake power less than 75 kW.

Compressor vent limits

ENGOs suggested that a lower compressor vent limit of 0.015 m3 per minute per rod packing should be set for reciprocating compressors to gain more emission reductions. Industry suggested the vent limit be increased to 0.033 m3 per minute per rod packing. Industry also mentioned that it is not possible for large centrifugal compressors to meet the proposed limit and that it should be increased.

The Department’s analysis confirmed that it is not feasible for the larger centrifugal compressors to meet the proposed limit of 0.34 m3 per minute per compressor and that raising the limit for these larger centrifugal compressors has a minimal impact on emission reductions. Regarding the limit for reciprocating compressors, other industry stakeholders confirmed that the limit is achievable and that there is no need to decrease it in order to meet the emission reduction target. Thus, the Department increased the vent limit requirements for large centrifugal compressors with a rated brake power of 5 MW or more to 0.68 m3 per minute per compressor. Meanwhile, the limit of 0.34 m3 per minute per compressor for centrifugal compressors with a rated brake power less than 5 MW, and of 0.023 m3 per minute per rod packing for reciprocating compressors remain unchanged from the proposed Regulations.

Compliance pathways

Industry commented that gas conservation is not always feasible for new compressors or at existing facilities and that destruction (i.e. combustion or flaring) should also be an acceptable compliance option.

The Department’s analysis demonstrates that there is a minimal impact to emission reductions if destruction is allowed for all new compressors and if an emissions limit for new compressors is added. These limits for new reciprocating compressors are 0.001 m3 per minute per rod packing and for new centrifugal compressors are 0.14 m3 per minute per compressor, essentially equivalent to a 95% destroy or capture requirement.

Well completion involving hydraulic fracturing
Exemptions

ENGOs expressed concerns about the proposed Regulations exempting Alberta and British Columbia from the requirements for well completions involving hydraulic fracturing as they believe that the provincial requirements for this emission source do not achieve the same reductions as the federal requirement would achieve. Industry, however, expressed their support for this exemption. No modification has been made to the Regulations as the Department’s analysis shows that emissions from well completions involving hydraulic fracturing are minimal in these two provinces due to actions already in place.

Industry stated that it is not possible to conserve gases from flowback when nitrogen and carbon dioxide are used in the fracturing process, as these gases may cause significant downstream plant or facility issues. The presence of nitrogen and carbon dioxide also prevents the gas from being combusted. In response to this comment, a modification was made to the Regulations to allow venting during well completion involving hydraulic fracturing when gas cannot sustain combustion.

General comments
Requests for mandatory conservation of gas

ENGOs advocated for mandatory conservation of gas, within both the facility venting and well completion involving hydraulic fracturing requirements, due to concerns regarding carbon dioxide and black carbon emissions from combustion. The Department has decided to allow destruction in the final Regulations as destruction is a suitable method to reduce methane emissions. In some cases, heavy oil facilities have no option but to destroy excess vented gas, as no cost-effective infrastructure is currently in place to allow conservation.

Coming into force dates

Industry requested a delay in coming into force dates of the requirements to provide more time for industry to adapt. ENGOs recommended taking action sooner by advancing the coming into force dates for the requirements.

The Department notes that the Regulations were originally planned to come into force in 2018 and 2020 as a result of the Government of Canada’s 2016 commitment. The coming into force dates of 2020 and 2023 were chosen to provide time for interested provinces to finalize regulatory regimes and, if interested, negotiate equivalency agreements with the Government of Canada. These dates are also a response to industry requests for more lead time to prepare for compliance, including being able to spread out capital retrofit costs, better manage operational changes, and ability to take advantage of provincial incentive programs, such as the exemption from the carbon tax levy and offset allowances in Alberta and royalty tax credits in British Columbia.

Registration requirements

Industry stakeholders commented that registration requirements were duplicative of provincial reporting and should be reduced or removed completely. They also suggested that information regarding equipment should be kept within company records and be made available to government on request. It was also noted that the 60-day registration timeline would be challenging.

To minimize administrative burden, the Department has amended the registration requirements such that the facilities which already report to an approved entity will not need to provide a full registration report under the federal regulations, decreasing the number of registrations to be submitted to the Department. Some elements of registration, such as equipment records at the facility level, have been changed to record keeping elements elsewhere in the Regulations. To add further flexibility, the Department extended the deadline for registration to 120 days after the first day of production.

Offshore facilities

Industry stakeholders, offshore boards, and provinces advised that offshore facilities have unique operational, logistical and safety conditions which require a different approach from that used for upstream oil and gas facilities. In recognition of the unique environment and configurations of offshore oil and gas operations, a section has been added to the Regulations regarding offshore-specific requirements. This new section includes flexibilities for LDAR inspections and leak repair timelines. Similarly to general LDAR requirements, alternative methods for inspections are now allowed and LDAR inspections frequency has been decreased to once per year (instead of three per year). Operators will now able to submit an application for a permit to request more time for repairs.

Regulatory impacts
Compliance costs

Several industry stakeholders indicated that the Department underestimated compliance costs attributable to the proposed Regulations. Many submissions indicated that the cost to comply with the LDAR requirements would be significantly higher than the Department’s estimates. Comments also focused on estimates of cost of equipment, such as air-driven pneumatic devices. Additionally, ENGOs advised that the Department overestimated costs of conservation equipment to comply with venting requirements.

The Department completed a full review of the cost assumptions used in the analysis of the proposed Regulations. This review included identifying key cost inputs called into question and consulting multiple sources to determine if these inputs required revision. Updates were made to the cost analysis to best reflect current evidence. These updates include increasing the assumed time to complete leak detection surveys, increasing the assumed cost to replace rod packing to comply with compressor requirements, and decreasing the cost of equipment to comply with venting requirements. Additionally, the estimated cost for air-driven pneumatic devices to comply with the proposed Regulations was increased. However, the Regulations no longer require zero bleed pneumatic devices resulting in a decrease in compliance costs. An updated cost breakdown was shared with industry, ENGOs, and service providers for further comment prior to finalizing the analysis.

Baseline methane emissions estimates

Several ENGOs and academics suggested that the Department re-evaluate baseline estimates of methane emissions in light of recent studies from the David Suzuki Foundation and Carleton University that found emissions to be significantly higher than estimated by the Department.

Methane emissions are estimated in the National Inventory Report in accordance with international reporting guidelines and methodologies agreed to by the UNFCCC, including methodological procedures and guidelines prescribed by the Intergovernmental Panel on Climate Change (IPCC). While the studies cited provide compelling evidence that methane emissions from the oil and gas sector are significantly higher than reported, they do not provide the source level data needed to produce updates to the inventory estimates. To address the possibility that methane emissions are higher than the Department’s estimates, a sensitivity analysis was conducted to better understand the impact of higher baseline methane emissions, which can be found in the Benefits and Costs section above.

Early industry action

Industry stakeholders commented that recent data shows significant reductions in facility level venting in the upstream oil and gas sector. They expressed concern that these reductions were not accounted for in the analysis of the proposed Regulations.

Recent provincial reporting data indicates that venting emissions reductions have been achieved through increased conservation efforts with regards to solution gas at oil facilities. Therefore, the analysis now attributes emission reductions previously attributed to the Regulations to industry action.

The analysis with this adjustment to the baseline demonstrates that, after this attribution of reductions to industry, there still exists a need for regulatory measures to achieve Canada’s methane emissions reduction target.

Oil and gas industry competitiveness

Several industry stakeholders expressed concerns that the Regulations would pose competitiveness challenges for the oil and gas sector. In particular, the potential for divergence in methane reduction requirements between the U.S. and Canada was cited as having the potential to shift investment away from the Canadian oil and gas industry. Additionally, concerns regarding the impact of cumulative costs of these and other regulatory requirements were raised as an additional issue that could affect the competitiveness of the sector.

In response to the potential financial and competitiveness impacts of the Regulations, several flexibilities have been included. For example, standards that will require significant capital investment, such as the facility production venting requirements and the pneumatic controller and pump requirements will not come into force until 2023, giving firms lead time to adjust. The Regulations will also allow facilities that experience technical or economic challenges from complying with the standard for pneumatic pumps to apply for a time-limited exemption permit. Further, the Department has made modifications to the Regulations from those proposed in CG-I that reduce compliance costs by an estimated $500 million over the period of analysis.

There will be a general alignment with U.S. measures when the Regulations come into effect for both new and existing facilities in 2020 and 2023, based on U.S. requirements currently in place. Since 2012, the U.S. EPA has been regulating tank venting, well completion involving hydraulic fracturing operations, low vent pneumatic devices, compressor venting and fugitive emissions from new onshore oil and gas facilities. Given the annual investments made to both maintain and increase crude oil and natural gas production, these requirements are expected to apply to most existing facilities by 2023. The emission sources covered by both regulatory regimes are generally aligned. Additionally, most U.S. oil and gas production is subject to more general state-level venting requirements, with some states, such as Pennsylvania, California, and Colorado, taking additional actions to manage fugitive emissions.

Analysis by the Department estimates that about 90% of compliance costs associated with final and proposed federal regulations affecting the oil and gas sector [including the Multi-Sector Air Pollutant Regulations and the Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector)] from 2018–2035 are attributable to the Regulations. Therefore, impacts to the competitiveness of the oil and gas sector beyond those described in the Competitiveness section above are not anticipated to be significant. While the analysis of the Regulations does not account for the cumulative impact of future measures, the Regulations will be included in the baseline for analysis of these measures.

Regulatory cooperation

International

Canada is working in partnership with the international community to implement the Paris Agreement to support the goal to limit temperature rise this century to well below 2 °C and to pursue efforts to limit the temperature increase to 1.5 °C.

In mid-2016, Mexico joined Canada in its commitment to reduce methane emissions from the oil and gas sector by 40% to 45% below 2012 levels by 2025. This commitment includes working together to improve methane data collection, emissions quantification and transparency of emissions reporting in North America. Any information and knowledge of cost-effective methane reduction technologies and practices is intended to be shared.

United States

In recognition of the integrated nature of the North American energy market, the Regulations will cover emissions from the same sources subject to current U.S. regulatory requirements. These sources include facility production venting, LDAR, well completion involving hydraulic fracturing, pneumatics and compressors. The structure of the Regulations is similar to the U.S. EPA’s regulatory regime, with modifications to reflect Canadian conditions (including existing requirements in various Canadian jurisdictions) and input from stakeholders.

The Regulations will cover all facilities whereas the U.S. EPA’s NSPS cover new and modified facilities. However, the nature of the upstream oil and gas industry is unique, with short-lived production cycles and constant renewal of production levels through the drilling of new wells to replace declining assets. The U.S. EPA initiated key amendments to the NSPS in 2012 with various additional requirements in 2015 and 2016. Given that the Regulations will not come into force in Canada until after 2020, the U.S. sector will have been facing similar requirements for a decade and most of the facilities will be impacted by the NSPS. Further, similar rules for existing facilities in several individual states (e.g. Wyoming, Colorado) have even more strict methane emission controls in place. If Canada were to limit application to only new and modified facilities, a significant portion of emissions will not be immediately captured, which will make it difficult to meet the methane reduction targets announced by the Government of Canada.

The current U.S. approach to regulating the oil and gas sector requires facilities to conduct a substantial number of administrative tasks. The Regulations differ from the NSPS in order to meet commitments in Canada’s Cabinet Directive on Regulatory Management to limit the administrative burden of regulations on business to what is necessary to achieve policy objectives. For example, the NSPS require facilities to report information on specific technical details annually. In order to minimize the administrative burden, the Regulations require on-demand reporting that is considered sufficient to meet data collection and compliance enforcement objectives.

The Regulations cover sources that are unique to Canada, such as certain heavy oil production methods. This oil production method is not included in the NSPS but is a significant source of methane emissions in Canada, and the Regulations are designed to address it through the facility venting limits.

Provinces and territories

Extended discussions took place with oil and gas regulators and provincial governments in Western and Atlantic Canada, in recognition of their key role in petroleum-producing regions of Canada. At the request of the Western provinces, recognizing that a significant share of the compliance costs will be incurred in this region, a special process was undertaken to develop a regulatory co-development framework between these provinces and the federal government. The framework includes commitments to work collaboratively, share information, meet regularly, and reduce regulatory duplication, with the goal of facilitating future potential negotiation of equivalency agreements. Harmonization with provincial measures has been incorporated into the Regulations. For example, the Regulations point explicitly to existing provincial emission measurement and quantification systems. Also, British Columbia and Alberta have been exempted from the venting limits during well completion involving hydraulic fracturing, since these jurisdictions already have adequate measures in place.

Rationale

GHG emissions, including hydrocarbons and CO2, are contributing to a global warming trend that is associated with climate change. The oil and gas sector is the largest GHG emitter in Canada and, more specifically, the largest industrial emitter of methane in Canada. Methane is the main component of natural gas. The majority of methane emissions from the oil and gas sector are released as a result of emissions from either fugitive or venting sources. Methane is a short-lived climate pollutant that can create significant near-term climate impacts. The latest emissions data indicates that the GHG emissions from the oil and gas sector account for 26% of Canada’s total GHG emissions. Without immediate action, it is expected that methane emissions from the oil and gas sector in Canada will continue to be released at high levels of about 45 Mt CO2e per year between 2018 and 2035, which represents a significant portion of Canada’s overall GHG emissions (722 Mt in 2015).

Canada and its international partners agreed to work together to implement the Paris Agreement and limit the temperature rise this century to well below 2 °C. Canada has also committed to introducing federal regulations to reduce methane emissions from oil and gas facilities to 40–45% of 2012 levels by 2025.

The Regulations introduce a set of performance standards to achieve significant emission reductions while providing facility and company flexibility to develop unique compliance strategies. As the Regulations do not prescribe specific compliance actions, multiple compliance pathways are available, allowing industry to plan and implement strategic company-wide solutions, introduce new technology, update existing equipment, or adapt operating practices. They will allow industry to introduce and remove emission controls over time as gas production changes, and allow industry to differentiate action based on their facility design and production profile.

It is estimated that the Regulations will lead to a 16.5 Mt reduction in CO2e emissions in 2030, an estimated 8% contribution to Canada’s GHG emissions reduction target under the Paris Agreement. It is also expected that the Regulations will lead to a 16.4 Mt reduction in methane emissions in 2025, a reduction of 40% below 2012 levels. These reductions will contribute to efforts to slow the rate of near-term global warming.

Further, the Regulations support an important pillar of the Pan-Canadian Framework on Clean Growth and Climate Change by reducing GHG emissions in a complementary fashion to the Government of Canada’s commitments to implement economy-wide carbon pricing. Since it is challenging to apply carbon pricing to all emissions, coverage gaps can exist without additional policy measures. In this regard, the Regulations constitute a complementary policy to carbon pricing that contributes to emission reductions in a cost-effective manner.

Since April 2016, the Department has held over 250 hours of consultations on the Regulations with industry, provinces, territories, environmental organizations and associations of Indigenous peoples. Industry has expressed concerns with the potential competitiveness impacts that the Regulations may have on Canada’s oil and gas sector, while environmental organizations expressed concerns regarding the lack of annual reporting and its impact on assessing industry compliance. The Department worked with stakeholders to minimize negative impacts and these groups have been generally supportive of the environmental objective of the Regulations.

In order to offset potential competitiveness concerns, the Regulations include several flexibilities, including small facility exemptions for certain standards. After consultations with stakeholders and provinces, the Department adjusted the coming-into-force dates to give more lead time to existing facilities before full compliance will be required. Given the relatively small incremental impact of the Regulations, and given that crude oil and natural gas are globally and continentally priced commodities, it is not expected that the Regulations will have a material impact on the prices of these products. Therefore, the Regulations are not expected to have impacts on consumers.

Between 2018 and 2035, the cumulative GHG emission reductions attributable to the Regulations are estimated to be approximately 232 Mt CO2e. Avoided climate change damages associated with these reductions are valued at $11.6 billion. In addition, cumulative VOC emission reductions are estimated to be 773 kt, with resulting health and environmental benefits equal to $240 million. The total cost of the Regulations is estimated to be $3.9 billion, which will be offset in part by the recovery of 351 petajoules (PJ) of natural gas, with a market value of $1.0 billion, resulting in expected net benefits of $8.9 billion.

Strategic environmental assessment

The Regulations have been developed under the Pan-Canadian Framework on Clean Growth and Climate Change. A strategic environmental assessment (SEA) was completed for this framework in 2016. The SEA concluded that proposals under the framework will reduce GHG emissions and are in line with the 2016–2019 Federal Sustainable Development Strategy (FSDS) goal of effective action on climate change. footnote56

Implementation, enforcement and service standards

Depending on the requirement, the Regulations will take effect in 2020 or 2023. The Regulations will be made under CEPA and enforcement officers will, when verifying compliance, apply the Compliance and Enforcement Policy for CEPAfootnote57 The Policy sets out the range of possible enforcement responses to alleged violations. If an enforcement officer discovers an alleged violation following an inspection or investigation, the officer will choose the appropriate enforcement action based on the Policy.

Compliance promotion activities are intended to assist the regulated community in achieving compliance. The approach for the Regulations includes developing and posting compliance promotion information such as frequently asked questions (FAQs) on the Department’s website to explain provisions of the Regulations, as well as undertaking various outreach activities such as workshops and informational sessions. The Department will respond to all stakeholder inquiries to ensure that the requirements of the Regulations are understood. These activities are targeted at raising awareness and assisting the regulated community in achieving a high level of overall compliance as early as possible during the regulatory implementation process. As the regulated community becomes more familiar with the requirements of the Regulations, compliance promotion activities are expected to decline to a maintenance level. The compliance promotion activities will be adjusted according to compliance analyses or if unforeseen compliance challenges arise.

The Department, in its administration of the regulatory program, will provide services and respond to permit 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 a technical guidance document that will include a description of the required information and format to be followed when submitting a permit for review.

Performance measurement and evaluation

The expected outcomes of the Regulations are directly related to international and domestic priorities to reduce methane emissions from the upstream oil and gas industry. The performance of the Regulations in achieving these outcomes will be measured and evaluated.

Specific outcomes (immediate, intermediate and final) have been developed as part of the implementation strategy for the Regulations. The expected immediate outcomes are awareness and understanding by the regulatees of their obligations under the Regulations. Expected intermediate outcomes of the Regulations include compliance by regulatees with the regulatory requirements. The expected final outcome is the reduction of methane emissions from the upstream oil and gas industry by at least 40% of 2012 levels by 2025.

Quantitative indicators and targets, where applicable, have been defined for each outcome and will be tracked annually through indicators such as enforcement activities, compliance promotion activities, registration and potential on-demand reporting.

The performance of the Regulations will be evaluated annually according to the program evaluation plan. Regular review and evaluation of the performance indicators will allow the Department to monitor the impacts of the Regulations on the upstream oil and gas sector and to evaluate the performance of the Regulations in reaching its intended targets.

Contacts

Cam Carruthers
Executive Director
Oil, Gas and Alternative Energy Division
Energy and Transportation Directorate
Environmental Stewardship Branch
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email:
ec.methane-methane.ec@canada.ca
Matthew Watkinson
Director
Regulatory Analysis and Valuation Division
Economic Analysis Directorate
Strategic Policy Branch
Environment and Climate Change Canada
200 Sacré-Cœur Boulevard
Gatineau, Quebec
K1A 0H3
Email:
ec.darv-ravd.ec@canada.ca