ARCHIVED — Vol. 151, No. 21 — May 27, 2017

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

  • Statutory authority
    • Canadian Environmental Protection Act, 1999
  • Sponsoring departments
    • Department of the Environment
      Department of Health

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Issues: 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 with a global warming potential 25 times that of carbon dioxide (CO2).

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

Cost-benefit statement: Between 2018 and 2035, the cumulative GHG emission reductions attributable to the proposed Regulations are estimated to be approximately 282 megatonnes of carbon dioxide equivalent (Mt CO2e). Avoided climate change damages associated with these reductions are valued at $13.4 billion. The total cost of the proposed Regulations is estimated to be $3.3 billion, which would be offset in part by the recovery of 663 petajoules (PJ) (see footnote 1) of natural gas, with a market value of $1.6 billion, resulting in expected net benefits of $11.7 billion.

“One-for-One” Rule and small business lens: The proposed Regulations would result in an increase in average annual administrative burden costs of around $1.1 million, or about $1,100 per business. The proposed 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 proposed Regulations to address the concerns of small businesses. These flexibilities are expected to reduce the cost of the proposal for small businesses by $56 million, or $120,000 per small business, over 18 years. The proposed Regulations would result in cumulative costs of about $14 million for small businesses, or $30,000 per small business.

Domestic and international coordination and cooperation: The proposed Regulations would deliver on the Prime Minister’s March 2016 commitment to reduce emissions of methane from the oil and gas sector by 40% to 45% below 2012 levels by 2025 and would be consistent with Canada’s commitment in the United States–Canada Joint Statement on Climate, Energy, and Arctic Leadership; the Paris Agreement; and the Leaders’ Statement on a North American Climate, Clean Energy, and Environment Partnership. Harmonization with provincial measures has been incorporated into the proposed Regulations to the extent possible.

Background

Methane (CH4) is a hydrocarbon 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 also a greenhouse gas (GHG) with a global warming potential 25 times greater than that of carbon dioxide (CO2). Oil and gas facilities account for 26% of Canada’s total GHG emissions and are Canada’s largest industrial emitters of methane. The majority of these emissions are released by fugitive (unintentional releases) and venting (intentional releases) sources.

Historical and current GHG emissions are causing the global average surface temperature to increase, leading to climatic changes such as the increased frequency and severity of extreme weather events. The impacts of climate change are already becoming evident. These include thawing permafrost, eroding coastlines and rising sea levels. These impacts are expected to worsen as temperatures rise. Climate change is of major concern for society due to impacts on natural habitats, agriculture and food supplies, infrastructure, and low-lying and coastal communities. (see footnote 2)

The Government of Canada is committed to taking action on climate change. At the United Nations Framework Convention on Climate Change (UNFCCC) conference in December 2015, the international community, including Canada, reached the Paris Agreement, an accord intended to reduce global GHG emissions in order to limit the rise in global average temperature to less than 2 °C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5 °C. As part of the Paris Agreement, Canada pledged to reduce national GHG emissions by 30% below 2005 levels by 2030, (see footnote 3) including a commitment to develop regulations to address methane emissions from the oil and gas sector. (see footnote 4)

In March 2016, Canada and the United States issued the Joint Statement on Climate, Energy, and Arctic Leadership and have committed to working together to implement their respective commitments under the Paris Agreement. Building on a history of joint activity to reduce air emissions, Canada and the United States agreed to take action to reduce methane emissions from the oil and gas sector, the world’s largest industrial methane source. Both countries adopted a target to reduce emissions of methane from their oil and gas sectors by 40% to 45% below 2012 levels by 2025. (see footnote 5) In June 2016, Mexico joined Canada and the United States and committed to the target as well under the Leaders’ Statement on a North American Climate, Clean Energy, and Environment Partnership. To achieve this target, Canada, the United States and Mexico committed to introducing or expanding federal regulations to reduce methane emissions from oil and gas facilities. (see footnote 6)

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 that can occur as gases at atmospheric pressure and liquids under higher pressures. (see footnote 7) Crude oil facilities extract liquid hydrocarbons, which can then be refined into gasoline, diesel, fuel oils, kerosene, jet fuel, asphalt, road oil and a variety of other fuels. Natural gas is a mixture consisting mostly of methane and is often used as fuel or to make materials and chemicals. (see footnote 8) 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 2012, close to 90% of methane emissions from the oil and gas sector came from upstream activities. Major sources of hydrocarbon emissions from the 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 storage tanks and wellhead casings. Methane has a global warming potential 25 times that of carbon dioxide and is a short-lived climate pollutant. Releasing methane into the atmosphere has significant climate change consequences in comparison to flaring (burning) methane. This is because flaring converts methane to 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 components on equipment piping such as valves, flanges, and connectors.

Well completion by 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. After 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. Any natural gas that is extracted along with the flowback material during this process could be vented into the atmosphere.

Pneumatic controllers and pumps: Pneumatic controllers are used in the oil and gas industry to measure and control parameters in the operations process, such as temperature, pressure, flow or liquid level. Pneumatic pumps are used to pump chemicals. Pneumatic instrumentation is commonly used by the industry due to its simplicity and reliability. A common practice is to use high-pressure field gas (see footnote 9) to operate these pneumatic devices. 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, and into the larger pipeline system for eventual delivery to the consumer. Compressors can vent gas through regular use and wear and tear of internal components.

Domestic emission control measures

Presently, there are no federal regulations established to regulate GHG emissions from the upstream oil and gas sector. There are some provincial instruments in place, particularly in British Columbia, Alberta and Saskatchewan, where the majority of onshore oil and gas activities are occurring. The Canadian Association of Petroleum Producers (CAPP) also has guidelines for flaring. However, these provincial instruments are not entirely 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 also exist for industry reporting of GHG emissions. While the province has a carbon tax in place, it does not apply to venting or fugitive emission sources from the oil and gas sector.

Alberta’s Directive 060 imposes requirements for incinerating and venting in the province at all petroleum industry wells and facilities. Venting reduction through solution gas (see footnote 10) conservation or gas flaring is based on reported vented emissions from the entire facility. Reported vented volumes include volumes from process vents, tank vents, and surface casing vents, but exclude venting from pneumatic instrumentation and pumps. Alberta also has in place the Specified Gas Emitters Regulation (SGER), which requires facilities that emit over a certain threshold to reduce emission intensity.

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 Saskatchewan.

The Canadian Standards Association (CSA) develops voluntary codes, and some of these standards 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.

International emission control measures

In April 2012, the United States Environmental Protection Agency (U.S. EPA) issued regulations under the Clean Air Act to reduce air pollution from the oil and natural gas industry. These new source performance standards (NSPS) included the first U.S. federal air standards for well completions at natural gas wells that are hydraulically fractured, new and modified tank emissions, pneumatic controllers at and between wellheads and natural gas processing plants, new and modified compressors and leak detection and repair (LDAR) programs for new and modified natural gas processing facilities.

The U.S. EPA updated the NSPS in 2016 to focus on the reduction of methane and volatile organic compound (VOC) emissions from new, reconstructed and modified oil and gas facilities. These updates added requirements to well completions to cover oil wells, extended pneumatic requirements to apply to gas transmission and to target methane, added methane requirements, extended applications to pipelines, extended LDAR to target methane specifically, and to apply to fugitive emissions from well sites, gas plants and compressor stations. The U.S. performance standards do not currently apply to existing facilities; however, they have been in place since 2016.

Issues

GHGs are a major contributor to 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 production and processing activities in the oil and gas sector in Canada were 192 Mt in 2014, accounting for 26% of total GHG emissions. (see footnote 11)

Without immediate action, it is expected that fugitive and venting 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 2012 and 2035.

Objectives

The Government of Canada has committed to undertake ambitious efforts to combat climate change, including international commitments under the United Nations Framework Convention on Climate Change (Paris Agreement and Copenhagen Agreement), and domestic commitments under the Pan-Canadian Framework on Clean Growth and Climate Change.

The objective of the proposed Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) [the proposed Regulations] is to achieve significant reductions in GHG emissions, through reductions in fugitive and venting emissions of hydrocarbons from the upstream oil and gas sector.

Description

The proposed Regulations would impose both general requirements and requirements that depend on a facility producing and receiving at least 60 000 m3 of hydrogen gas in a year. The requirements relate to production processes and equipment and have the effect of reducing the emission of methane and the targeted VOCs from the upstream oil and gas sector.

  • Facility production venting: Upstream oil and gas facilities would be required to limit vented volumes of hydrocarbons to 250 m3 per month as of January 1, 2023. These facilities would need to capture the gas and either use it on site, reinject it underground, send it to a sales pipeline, or route it to a flare. Facilities that vent less than 40 000 m3 of gas per year without destroying or selling any would not be required to destroy or conserve it.
  • Leak detection and repair: Upstream oil and gas facilities, except single wellheads, would be required to implement leak detection and repair (LDAR) programs as of January 1, 2020. Regular inspections would be required three times per year, and corrective action would be required if leaks are discovered. Leaks would need to be repaired within 30 days, if repairs are possible without shutting down the equipment. If repairs are not possible without shutting down the equipment, the facility operator would be required to schedule a shutdown to take corrective action before the volume of gas from the leak is larger than the volume of gas that would be released by shutting down the equipment. If the facility is located offshore and the equipment cannot be repaired while operating, corrective action would need to be taken within 365 days.
  • Well completion by hydraulic fracturing: These sites would be required to conserve or destroy gas instead of venting as of January 1, 2020. This standard would not apply to British Columbia or Alberta, where existing provincial measures cover these activities.
  • Pneumatic controllers: Controllers at facilities with a total compressor power rating of at least 745 kilowatts (kW) would be prohibited from emitting hydrocarbon gas as of January 1, 2023. Other facilities would be required to use low-emitting pneumatic controllers.
  • Pneumatic pumps: Pumps would be prohibited from emitting hydrocarbon gas or be equipped with an emissions control device at facilities where liquid pumping exceeds 20 L per day of liquid as of January 1, 2023. Permits for pneumatic pumps would be available when it is technically or economically infeasible for a facility to comply.
  • Compressors: Measurement of the flow rate of hydrocarbon emissions would be required from sealing systems, at least once per year, as of January 1, 2020. Corrective action would be required if those emissions exceed 0.023 m3 per minute for reciprocating compressors and 0.17 m3 per minute for centrifugal compressors. All new compressors installed would be required to capture gas from sealing systems.

All upstream oil and gas facilities would also be required to register and keep records in order to demonstrate compliance with the proposed Regulations. Facilities would also be required to submit reports at the request of the Minister of the Environment (the Minister).

Designation Regulations

The Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) [the Designation Regulations] designate various regulatory provisions from CEPA regulations that set out an increased fine range following a conviction for an offence involving harm or risk of harm to the environment, or obstruction of authority. The proposed Regulations would be listed in the Designation Regulations, which would need to be amended to reflect the addition of new offences pertaining to the proposed standards.

Regulatory and non-regulatory options considered

In consideration of how to address the public policy issue, the Department of the Environment (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. 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 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.

For these reasons, current and announced provincial measures would not alone 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, have been considered as options for methane mitigation. Voluntary instruments provide greater flexibility for stakeholders in meeting the objectives of the policy but also 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 arrive at voluntary goals that provide assurance of 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 would not likely amount to the emission reductions to meet Canada’s GHG targets. Voluntary approaches were ultimately rejected for these reasons.

Market-based approach

In October 2016, the Prime Minister announced a plan on pricing carbon pollution that would set a floor price for carbon pollution across Canada. However, fugitive and venting emissions are often from dispersed sources of emissions from a large number of mostly small facilities, which are unlikely to have adequate quantification protocols for tracking emissions. In fact, existing Canadian carbon pricing systems in British Columbia, Ontario and Quebec do not cover these emissions since the facilities do not meet the policy threshold. Therefore, a market-based approach was not considered sufficient to address fugitive emissions and venting releases of methane in the oil and gas sector.

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; would not capture unique Canadian emission sources such as heavy oil; would impose substantial, unnecessary administrative burden on regulated parties that would be inconsistent with commitments in Canada’s Cabinet Directive on Regulatory Management to control the administrative burden of regulations on business; and, would not initially cover a significant portion of existing facilities, making it difficult to meet the reduction targets announced by the Prime Minister (see footnote 12) in 2016. For these reasons, close alignment with the U.S. NSPS was rejected.

Regulatory approach under CEPA

The Government of Canada is committed to reducing methane and GHG emissions in the atmosphere in light of Canada’s international agreements. The implementation of a regulation made under CEPA is considered a primary instrument to achieve this goal as it is very likely to ensure that emission reductions are achieved. This approach ensures that hydrocarbon 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 proposed Regulations would 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, which can enable these jurisdictions to be front-line regulators where they have legally binding regimes that produce equal or better environmental outcomes.

The proposed Regulations are based on current U.S. source-by-source rules that apply to new and modified oil and gas facilities, which were finalized in 2012 and 2016, with modifications to reflect Canadian conditions (including existing requirements in various Canadian jurisdictions) and input from stakeholders. The proposed Regulations would exempt the provinces of British Columbia and Alberta from the well completion by 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 by hydraulic fracturing requirements under the proposed Regulations would 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 proposed Regulations are estimated to be approximately 282 Mt CO2e. Avoided climate change damages associated with these reductions are valued at $13.4 billion. The total cost of the proposed Regulations is estimated to be $3.3 billion, which would be offset in part by the recovery of 663 petajoules (PJ) (see footnote 13) of natural gas, with a market value of $1.6 billion, resulting in expected net benefits of $11.7 billion.

As shown in Figure 1 below, the most significant costs would be incurred in 2023, as standards requiring significant capital investment come into force. Beyond 2023, it is expected that emissions of methane would be reduced by more than 20 Mt (in CO2e) annually. In 2030, there would be net GHG emission reductions of about 20 Mt.

Figure 1: Baseline scenario and policy scenario methane emissions and compliance costs by year

Graphic-Detailed information can be found in the surrounding text.

Analytical framework

The impacts of the proposed Regulations have been assessed in accordance with the Treasury Board Secretariat (TBS) Canadian Cost-Benefit Analysis Guide. (see footnote 14) Regulatory impacts have been identified, quantified and, where possible, monetized.

The expected key impacts of the proposed Regulations are demonstrated in the logic model (Figure 2) below. Compliance with the proposed Regulations would result in incremental capital and operating costs for industry, and administrative costs for both industry and Government. Compliance would also result in reduced releases of natural gas (a mixture consisting of mostly methane), which would reduce GHG and volatile organic compound (VOC) (see footnote 15) releases to the atmosphere. Reductions in GHG emissions from the oil and gas sector would contribute towards mitigating climate change impacts. Reductions in VOCs would improve air quality which results in environmental and health co-benefits. Methane gas that would otherwise have been wasted through fugitive leaks or venting would now be flared or conserved as a potential energy source.

Figure 2: Logic model for the analysis of the proposed Regulations

Compliance with the Proposed Regulations

Reductions in GHG Emissions

Reduction in Climate Change Impacts

Social Benefits

Conserved Gas

Increased Productivity

Reductions in VOC Emissions

Improved Air Quality

 

Compliance Costs

Social Costs

Administrative Costs

The analysis compares the expected incremental impacts of two scenarios: a baseline scenario and a regulatory scenario. The baseline scenario assumes a status quo in which the proposed Regulations are not implemented while the regulatory scenario assumes that the proposed Regulations are implemented. In addition, only existing provincial measures on limiting methane emissions originating from oil and gas facilities are considered in the analysis. All benefits and costs presented below are incremental to the baseline scenario, unless otherwise specified.

The time frame considered for this analysis is 2018 to 2035. The Department assumes the proposed Regulations would be published in the Canada Gazette, Part II, by the end of 2017. Thus, some early compliance by new facilities is expected beginning in 2018. Ongoing incremental costs and benefits following 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 time frame for assessing impacts in this analysis is the 2018 to 2035 period (18 years), which is sufficient to fully demonstrate impacts and demonstrate whether or not the benefits of the proposed Regulations are likely to exceed the associated costs. A longer time period of analysis would show a larger net benefit because most of the costs of the proposed Regulations are upfront costs incurred in 2023, as shown in Figure 1 above.

The proposed Regulations contain five production, processing and transmission standards designed to reduce fugitive and vented emissions from upstream oil and gas producers. Leak detection and repair programs, well completion by hydraulic fracturing requirements and compressor limits would come into force in January 2020 while facility production venting requirements and emission limits for pneumatic controllers and pumps would come into force in January 2023.

All monetary results are shown in 2015 Canadian prices after inflating any non-2015 prices. When shown as present values, future year impacts have been discounted at 3% per year to 2016 (the year of the analysis), as per TBS guidance.

Analysis of regulatory coverage and compliance

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

Regulatory coverage

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

The proposed Regulations would cover facilities that have the potential to emit hydrocarbons above a 60 000 m3 per year threshold in any of the past five years and to facilities using equipment subject to the proposed standards (covered facilities). Currently, some facilities are expected to already meet the compliance requirements of the proposed Regulations, in part or completely, due to provincial measures. Facilities that would need to take incremental action to comply with the proposed Regulations are considered affected facilities. The cost-benefit analysis focuses on affected facilities when estimating incremental impacts of the proposed Regulations.

In order to estimate affected facilities in the oil and gas sector, upstream oil and gas facility numbers were obtained from Petrinex (Petroleum Information Network) (see footnote 16) for Alberta and Saskatchewan in 2012 and 2013, and forecasted using the production forecasts of crude oil and natural gas from the NEB. (see footnote 17) Due to limited available information, the number of facilities in the rest of Canada was forecasted using production to facility ratios calculated for Alberta and Saskatchewan. The Petrinex database was also used to determine and estimate the number of facilities in the oil and gas sector that would be covered by the proposed Regulations.

As mentioned above, the number of affected facilities that would require compliance action for each of the proposed standards was estimated using a combination of consultation and various consultant reports. (see footnote 18) The expected compliance strategies to be adopted by the oil and gas industry in order to meet the requirements for each standard under the proposed Regulations are described below.

Compliance with facility production venting requirements

The proposed Regulations would require covered facilities to limit vented gas to 3 000 m3 per year. Affected facilities would comply with the proposed Regulations either by destroying or conserving the gas. It is assumed that it would be less costly for a facility to conserve its vented gas if its gas production net of on-site fuel use is greater than 550 000 m3 per year. Also, if the facility is already selling more than 10 000 m3 of gas per year, it is assumed that it would conserve gas. If neither of the conditions are true, it is assumed the facility would destroy the gas by flaring.

Compliance with LDAR requirements

The proposed Regulations would require that a leak inspection take place three times a year for all covered facilities. As well, when a leak is detected, corrective action would be required to be taken and a reinspection would need to be done using a portable monitoring instrument.

Based on industry consultation, it is expected that in the baseline scenario, facilities in provinces without regulatory measures in place would perform LDAR about once every four years. In provinces with 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.

To comply with the proposed Regulations, affected facilities would perform LDAR three times a year. Facilities are assumed to hire a professional to conduct leak detection using an optical gas imaging (OGI) camera under the regulatory scenario. Should a leak be detected, a facility would be required to repair the leak and reinspect the leak using a portable monitoring instrument (a “sniffer”).

Compliance with the well completion by hydraulic fracturing requirements

The proposed Regulations would require new hydraulic fracturing or refracturing operations to conserve or destroy vented gas, except in British Columbia and Alberta (where 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 hydraulic fracturing wells would flare emitted gases to comply with the proposed Regulations.

Compliance with pneumatic controller and pump requirements

The proposed Regulations would require affected facilities with pneumatic controllers to use low/no-bleed controllers, and affected facilities with pneumatic pumps to use electric pumps or pumps equipped with emissions control devices.

It is assumed that batteries (see footnote 19) and well sites would not have compressors that exceed the 745 kW threshold, so high-bleed pneumatic controllers would be replaced with low-bleed pneumatic controllers. As well, pneumatic pumps at batteries and well sites are assumed to be replaced with solar pumps.

Conversely, compressor stations and gas processing facilities are assumed to have compressors that exceed the 745 kW threshold. Pneumatic controllers would therefore need to be non-hydrocarbon emitting. These facilities are assumed to comply with the proposed Regulations by installing an air compressor and converting to air driven pneumatic controllers. Furthermore, these facilities are not expected to have pneumatic pumps requiring replacement, since the majority of pneumatic pumps are used at batteries and well sites.

For existing facilities, it is assumed that devices would be replaced in 2023. It is assumed that new facilities would purchase low-bleed controllers or solar pumps, beginning in 2018.

Compliance with compressor requirements

The proposed Regulations would set emission limits for both centrifugal and reciprocating compressors: 0.17 mper minute and 0.023 mper minute respectively. If the measurement exceeds the rate limit for the compressor type, corrective action must be taken and the rate of emissions must be measured again. In addition, any new compressors installed would be required to conserve vented gas.

It is expected that affected facilities with reciprocating compressors would replace rod packing every three years compared to replacement every five years in the baseline scenario to comply with the proposed standard. (see footnote 20) Affected facilities with centrifugal compressors are expected to install recovery systems on their wet seal degassing units to recover and reroute methane. (see footnote 21) The degassing recovery system would allow facilities with wet seals to forego retrofitting their compressors with dry seals and still mitigate methane emissions with little downtime.

Table 1: Expected regulatory strategies per standard

Standard

Year of Coming Into Force

Anticipated Compliance Action

LDAR

2020

  • Professionals would be hired to perform leak detection with OGI camera
  • Repaired leak would be reinspected with portable monitoring instrument

Well completion by hydraulic fracturing requirements

2020

  • Fractured and refractured wells would flare emitted gases

Compressors

2020

  • Rod packing in reciprocating compressors would be replaced every three years instead of five years
  • New reciprocating compressors would install vent capture device
  • Centrifugal compressors would install recovery unit on wet seal degassing system

Facility production venting requirements

2023

  • Facilities with net gas production greater than 550 000 m3 per year, or with gas sales greater than 10 000 m3 per year would conserve vented gas
  • Other facilities (i.e. with lower production or sales) would destroy gas

Pneumatics

2023

  • High-bleed controllers would be replaced with low-bleed controllers at batteries or well sites
  • Gas-driven devices would be air driven with the installation of an air compressor at compressor stations and gas processing plants
  • Pneumatic pumps would be replaced with electric (solar) pumps
Industry costs of compliance by standard

Facilities covered by the proposed Regulations are expected to carry 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.

Facility production venting compliance costs

Affected facilities are expected to either conserve the previously vented gas by installing a vapour recovery unit (VRU), or install a flare to destroy the gas. It is estimated that about 3 000 facilities would conserve gas, while about 4 000 facilities would flare it. Compliance costs borne by industry would include the operating costs associated with ongoing operation and management, and capital costs for VRU and flares. (see footnote 22) Capital costs are estimated at $150,000 to $200,000 per facility to purchase and install a VRU, and at $150,000 per facility to purchase and install a flare. Annual operating costs are estimated at $10,000 per facility to conserve gas, and at $5,000 per facility to flare. It is estimated that the facility production venting standard would result in a cost to industry of $1,201 million between 2018 and 2035.

LDAR compliance costs

The proposed Regulations would require affected facilities to undertake leak detection more frequently than they otherwise would have in the baseline scenario. It is estimated that about 42 000 facilities would be covered by the LDAR requirements. Compliance costs to industry would include the capital cost of putting in place an LDAR data collection system of $21,000 per facility. As well, costs would be incurred to detect leaks using OGI equipment (through the hiring of a professional). (see footnote 23) The number of components per facility is used to estimate the time it would take a consultant to conduct OGI leak detection, assumed to cost $190 an hour, which includes the wage paid to the consultant plus the rental rate for the camera. Upon completion of a repair, the proposed Regulations require that the repaired leak be inspected using a portable monitoring instrument (a “sniffer”) in accordance with the U.S. Environmental Protection Agency Method 21. Per component, the cost of inspection (with an OGI camera) and reinspection (with a sniffer) is estimated to be 43 cents. (see footnote 24) It is estimated that the LDAR standard would result in a cost to industry of $374 million between 2018 and 2035.

The analysis assumes that leaks are random and independent events and that new leaks are unlikely to reoccur within the baseline reinspection period (up to four years). Therefore, the number of leaks that are detected is essentially the same (change of less than 1%) in the baseline and regulatory scenarios. Under the regulatory scenario, leaks would, however, be detected earlier than they would in the baseline scenario. As a result, the analysis has not considered the incremental cost of repairs.

Well completion by hydraulic fracturing requirements compliance costs

The analysis assumes that under the regulatory scenario, all affected fracturing and refracturing wells would flare emitted gases. It is estimated that about 15 000 oil and gas wells would be required to install a flare over the time frame of the analysis. It is expected that flaring well completion emissions would cost $4,000 (flares required for well completions are generally rented on a temporary basis and are therefore less costly than facility flaring described above). (see footnote 25) It is estimated that this standard would result in a cost to industry of $41 million between 2018 and 2035.

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. (see footnote 26) The analysis assumes that new facilities would carry the incremental cost difference between a high-bleed device and a compliant device, while existing facilities would carry the full cost of a new device.

It is estimated that the number of gas-driven pneumatic devices per facility would range between 0 and 18 for most facilities. (see footnote 27) Compliance costs to industry would consist of the incremental capital and labour cost of replacement or retrofit ranging from $0 to $917 for new facilities, and $276 to $2,348 for existing facilities. At compressor stations and gas processing facilities, it is expected that an air compressor would be installed to convert existing devices to be air driven. This is estimated to cost $65,000 per facility. (see footnote 28) For pneumatic pumps, it is assumed that facilities would replace pumps with solar pumps, which is estimated to cost $7,500 for new facilities and $16,200 for existing facilities. (see footnote 29) It is estimated that the pneumatics standard would result in a cost to industry of $1,492 million between 2018 and 2035.

Compressors compliance costs

Facilities with reciprocating compressors would replace rod packing more frequently as a result of the proposed Regulations. It is estimated that the rod packing would need to be replaced more frequently for about 9 000 reciprocating compressors, and the incremental cost to replace the rod packing for a reciprocating compressor more frequently is estimated at an annualized cost of $300. In addition, approximately 1 500 newly installed reciprocating compressors would be required to capture all emitted gases. (see footnote 30) The estimated cost to install conservation equipment would be about $27,000 per compressor.

Facilities with centrifugal compressors are expected to augment their compressors with a recovery unit that conserves the gas vented from the compressor’s wet seal degassing system. It is estimated that there are around 90 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 would result in a cost to industry of $157 million between 2018 and 2035.

Summary of industry compliance costs

Compliance costs associated with the proposed Regulations would increase the marginal cost of producing natural gas (and other fuels) in Canada. With no offsetting effects, these incremental costs are expected to decrease the quantity of natural gas produced in Canada, relative to the baseline scenario. Given the integrated nature of the North American market for natural gas, it is assumed that these decreased quantities would be replaced by imported natural gas. (see footnote 31) For the purposes of this analysis, industry compliance costs of $3.3 billion (see Table 2) are used as a proxy for the value of this compliance cost effect. These compliance costs would be offset, in part, by the recovery of 663 PJ of natural gas with a market value of $1.6 billion, described in the benefits analysis below.

Table 2: Industry compliance costs by proposed standard (millions of dollars)

Proposed Standard

2018–2025

2026–2030

2031–2035

Total

Facility production venting requirements

749

229

222

1,201

Leak detection and repairs

187

102

85

374

Well completion requirements

16

17

8

41

Pneumatic controllers and pumps

1,411

53

28

1,492

Compressors

74

45

38

157

Total

2,437

446

381

3,265

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

Most of the compliance costs are expected to occur in 2023 (about $2.0 billion as shown in Figure 1 above), when the facility production venting, and pneumatic device and pump requirements come into effect.

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 proposed Regulations would require regulatees to register facilities, keep records, and submit registration and compliance reports. These industry administrative costs are estimated to be $21 million between 2018 and 2035. (see footnote 32)

The Department would also incur costs to enforce the proposed Regulations, conduct compliance promotion and administer the proposed Regulations. In 2018, an estimated one-time cost of about $209,000 is expected to be required for the training of enforcement officers and $50,000 to meet information management requirements. The annual inspection cost is estimated to be $571,500. This cost includes inspections, investigations, measures to deal with alleged violations and prosecutions and is estimated to be $8 million between 2018 and 2035.

Compliance promotion activities are intended to encourage the regulated community to achieve compliance. Compliance promotion costs include distributing the proposed Regulations, 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 $148,000 between 2018 and 2022.

The proposed Regulations allow for a temporary permitted exemption for facilities where meeting the requirements for pneumatic pumps would be technically or economically infeasible. These permits would need to be reviewed and approved by the Government of Canada. The total cost of permit reviews is estimated to be $35,000 between 2018 and 2035.

Table 3 below summarizes the administrative cost to ensure compliance for both industry and Government.

Table 3: Administrative costs for industry and Government (millions of dollars)

 

2018–2025

2026–2030

2031–2035

Total

Industry administrative costs

11

6

5

21

Government administrative costs

5

2

2

8

Total administrative costs

15

8

7

29

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 $29 million between 2018 and 2035.

Benefits of regulatory coverage and compliance

The proposed Regulations would reduce vented and fugitive emissions of methane, a potent GHG, through the requirements to conserve fugitive and vented natural gas. This means that natural gas that would otherwise have been wasted would be conserved as a potential energy source. In addition, emissions of VOCs would 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 CO2 emission reductions, and the social cost of methane (SCCH4) has been applied to the 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.

Given the resource-intensive and time-consuming nature of air quality modelling, the Department is still in the process of finalizing air quality modelling results for reductions in VOCs. Therefore, VOC emissions reductions have not been monetized for this analysis.

Quantification of benefits

The analysis estimated the conserved gas and quantified the emission reductions by first developing detailed engineering emissions estimates for each proposed standard, 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 natural gas reductions, natural gas emission factors for the various standards and product types were multiplied by the total number of devices for the respective standard. This procedure calculates the total amount of natural gas that would be recovered by implementing the proposed 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

  • — For facility production venting requirements, provincial data on facility venting and flaring volumes were used to estimate the baseline emissions, and compared to the required reductions as per the proposed Regulations;
  • — For LDAR, the emission factors for the policy scenario are obtained using the methods from the 1995 U.S. EPA Protocol and applying factors from an engineering assessment of fugitive equipment leak emission factors undertaken in 2014; (see footnote 33), (see footnote 34)
  • — For well completion by hydraulic fracturing requirements, emission factors are obtained from the U.S. EPA; (see footnote 35)
  • — For pneumatic devices, emission factors were derived from an engineering assessment of pneumatic devices undertaken in British Columbia in 2013; (see footnote 36) and
  • — For compressors, the emission factors for the reciprocating compressors are estimated using the Environmental Defense Fund (EDF) sawtooth method. (see footnote 37) The EDF study provided a start and end emission factor which increases linearly to produce a timeline of emission based on months passed since the last rod packing change. For centrifugal compressors, the emission factors are obtained from an engineering assessment of compressors undertaken in 2014 by the U.S. EPA. (see footnote 38)

To separate emissions of natural gas into the different pollutants, the composition of emitted and conserved natural gas is determined using estimates of gas composition from the Clearstone Engineering report, (see footnote 39) with the exception of gas from facility production venting, as these composition ratios were obtained from a combination of reports from provinces. (see footnote 40) 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 4 below.

Table 4: Composition of gas by proposed 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

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 estimating GHG emission trends and policy impacts in Canada. This analysis uses emissions projections as reported in Canada’s Second Biennial Report on Climate Change to United Nations Framework Convention on Climate Change. (see footnote 41)

The baseline engineering emission estimates were compared to the departmental baseline emission forecast to obtain a ratio or scaling factor. This scaling factor was applied to the engineering estimates to derive final incremental emission reduction estimates for the proposed Regulations. The scaling factor is broken down by province, by sector, and by pollutant (CH4, CO2 and VOC), but not by emission source. Further scaling was done where necessary to ensure that incremental reductions do not exceed baseline emission estimates.

Greenhouse gases emission reductions

The proposed Regulations would reduce methane emissions that would be emitted into the atmosphere. At the same time, the proposed Regulations are estimated to result in a slight increase in flaring activities, which would slightly increase CO2 emissions. The proposed Regulations would reduce 12 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 295 Mt CO2e between 2018 and 2035. The increase in CO2 as a result of the increase in flaring activities is estimated to be 14 Mt over the time frame of analysis.

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 282 Mt CO2e of GHG emissions would be reduced between 2018 and 2035 as a result of the proposed Regulations as seen in the table below.

Table 5: GHG emission reductions per proposed standard (in Mt CO2e)

 

Net GHGs (CH4 + CO2)

CH4

CO2

Proposed Standard

2018–2025

2026–2030

2031–2035

2018–2035

2018–2035

2018–2035

Facility production venting requirements

26

44

42

112

125

–13

Leak detection and repairs

23

20

20

64

64

0

Well completion requirements

2

1

1

4

5

–1

Pneumatic controllers and pumps

19

27

26

72

72

0

Compressors

9

10

11

30

30

0

Total

80

102

100

282

295

–14

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. (see footnote 42) 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).

In 2018, the SCC and SCCH4 are estimated at $44 and $1,273 respectively, whereas in 2035, the SCC and SSCH4 are estimated at $61 and $2,026. Over the time frame of analysis, the SCCH4 is applied to 12 Mt of methane reductions and the SCC is applied to 14 Mt increase in CO2 as a result of flaring. The present value of the reduction of GHGs is around $13.4 billion.

Table 6: Total present value of GHG emission reductions (millions of dollars)

Proposed Standard

2018–2025

2026–2030

2031–2035

Total

Facility production venting requirements

1,283

2,117

2,017

5,417

Leak detection and repairs

1,118

950

944

3,012

Well completion by hydraulic fracturing requirements

78

71

41

189

Pneumatic controllers and pumps

927

1,280

1,198

3,405

Compressors

453

455

497

1,406

Total

3,858

4,873

4,697

13,429

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.

It is expected that the proposed Regulations would lead to a 21 Mt reduction in methane emissions in 2025, a reduction of 41% below 2012 levels, falling in the range of a 40% to 45% reduction as committed in March 2016. It is also expected that the proposed Regulations would lead to a 20 Mt reduction in net GHG emissions in 2030, an estimated 7% contribution to Canada’s GHG emissions reduction target under the Paris Agreement.

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 proposed Regulations would result in more efficient operations, with limited methane venting, reduced leakage, and the conservation of approximately 663 PJ of natural gas (see Table 7). This improved efficiency would increase the marginal productivity of natural gas production, and to some extent offset the industry compliance costs described above. It would also increase the quantity of natural gas produced in Canada, and displace imported supply. (see footnote 43) Given that recovered natural gas has already been extracted, and that the costs associated with its recovery were accounted for in the industry compliance costs, the full market value of this recovered natural gas is assumed to be a reasonable proxy for the value of this conserved resource. The conservation of VOCs has not been quantified due to the relatively small quantities and the variability of hydrocarbon make-up of these VOCs.

Table 7: Estimation of conserved gas by proposed standard (in PJ)

Proposed Standard

2018–2025

2026–2030

2031–2035

Total

Facility production venting requirements

69

115

112

295

Leak detection and repairs

52

45

45

141

Well completion by hydraulic fracturing requirements

0

0

0

0

Pneumatic controllers and pumps

43

60

57

160

Compressors

21

21

24

66

Total conserved gas

184

241

238

663

Note: Numbers may not add up due to rounding.

A market price for natural gas was used to estimate what companies are willing to pay for conserved resources. Estimates of future Alberta Energy Company natural gas prices (AECO-C) were calculated using the Henry Hub natural gas price forecasted by the NEB and subtracting $0.65/gigajoule (GJ) to reflect historic spreads between the two prices. (see footnote 44) This price forecast, ranging from $2.43/GJ in 2018 to $3.68/GJ in 2035, was then applied to the estimated quantity of methane that would be conserved. The value of conserved gas as a result of the proposed Regulations is estimated to be $1.6 billion over the time frame of the analysis (see Table 8). (see footnote 45) This market price estimate may overvalue society’s willingness to pay to conserve natural gas, an uncertainty that has been considered in the sensitivity analysis below.

Table 8: Total present value of conserved gas (millions of dollars)

Proposed Standard

2018–2025

2026–2030

2031–2035

Total

Facility production venting requirements

178

280

245

702

Leak detection and repairs

134

109

99

341

Well completion requirements

0

0

0

0

Pneumatic controllers and pumps

111

146

125

383

Compressors

54

52

52

158

Total value of conserved gas

478

586

521

1,585

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

Volatile organic compounds

The proposed Regulations, through reductions of fugitive and venting emissions, would also reduce by up to 769 kt the quantity of VOCs that would enter the atmosphere over the time frame of analysis.

Table 9: Estimated VOC reductions by proposed standards (in kt)

Proposed Standards

2018–2025

2026–2030

2031–2035

Total

Facility production venting requirements

115

208

217

541

Leak detection and repairs

33

29

30

91

Well completion requirements

3

3

2

8

Pneumatic controllers and pumps

25

36

35

96

Compressors

9

11

13

33

Total VOC reductions

186

286

297

769

Note: Numbers may not add up due to rounding.

VOCs contribute to the formation of ground level ozone and particulate matter, which are the main constituents of smog. Smog is known to have adverse effects on human health and the environment. The Department uses the following three different models to estimate the health and environmental impacts of air pollution: a model to estimate VOC emission impacts on air quality; a model to estimate health impacts associated with the changes in air quality; and a model to estimate environmental impacts associated with the changes in air quality. Given the resource-intensive and time-consuming nature of air quality modelling, the Department is still in the process of finalizing the modelling results. Thus, monetized health and environmental benefits attributable to VOC reductions are not available at this time, but are planned to be presented in the analysis for publication in the Canada Gazette, Part II.

Summary of benefits and costs

The proposed Regulations are expected to achieve 282 Mt CO2e in GHG emission reductions, 663 PJ of conserved gas and 769 kt of VOC emission reductions, as shown in Table 10 below. These quantitative benefits have been monetized where possible, or assessed as qualitative benefits.

By 2035, the proposed Regulations are estimated to result in cumulative net GHG emission reductions of 282 Mt, valued at around $13.4 billion, and cumulative gas conserved of 663 PJ, valued at around $1.6 billion. The total benefits of the proposed Regulations are valued at around $15.0 billion. The proposed Regulations would also result in costs to industry and government of $3.3 billion. The net benefits of the proposed Regulations for Canadians are $11.7 billion. These costs and benefits associated with the proposed Regulations are summarized in Table 10.

Table 10: Summary of benefits and costs

Monetized Impacts (millions of dollars)

2018–2025

2026–2030

2031–2035

Total

Climate change benefits

3,858

4,873

4,697

13,429

Value of conserved gas

477

586

521

1,585

Total benefits

4,336

5,460

5,218

15,014

Industry compliance costs

2,437

446

381

3,265

Industry administrative costs

11

6

5

21

Government administrative costs

5

2

2

8

Total costs

2,453

454

389

3,295

Net benefits

1,883

5,006

4,895

11,719

Quantified benefits

Net GHG reduction (Mt CO2e)

80

102

100

282

Gas conserved (PJ)

184

241

238

663

VOC reduction (kt)

186

286

297

769

Qualitative benefits

Health and environmental benefits due to VOC emission reductions.

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

The proposed Regulations are expected to achieve a net 182 Mt CO2e cumulative reduction in GHG emission reductions by 2030, which would 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 $2.9 billion would be incurred. However, conserved gas valued at $1.1 billion over the same time frame (2018–2030) is also expected. Overall, as indicated in Table 11, the anticipated GHG emission reductions would be achieved at an estimated cost per tonne of $16, and a net cost per tonne of about $10.

Table 11: Cost per tonne of GHG emission reductions (2018–2030)

Type of Cost per Tonne

Costs
(millions of dollars)

GHG Emission Reductions
(Mt CO2e)

Cost per Tonne

Cost per tonne

2,900

182

16

Net cost per tonne

1,800

182

10

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 proposed Regulations would 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 12 shows the breakdown of overall costs, emission reductions, and conserved gas attributable to the proposed Regulations across Canadian regions. As expected, due to the concentration of oil and gas activities in the Western provinces, the major impacts are expected in British Columbia, Alberta, and Saskatchewan with the remainder distributed throughout the rest of Canada (ROC).

Table 12: Distribution of quantified benefits and monetized costs across regions

Category

B.C.

Alta.

Sask.

ROC

Total

Reduced net GHG emissions (Mt CO2e)

19

183

77

3

282

Gas conserved (PJ)

43

433

180

7

663

Reduced VOC emissions (kt)

35

560

168

5

769

Compliance costs (million $)

238

2,293

715

19

3,265

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

Impacts by product

The compliance costs associated with the proposed Regulations would also vary by product. Table 13 shows the breakdown of overall costs and benefits of the proposed 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 13: Distribution of quantified benefits and monetized costs across products

Category

Light Oil

Heavy Oil

Natural Gas

Total

Reduced net GHG emissions (Mt CO2e)

59

99

124

282

Gas conserved (PJ)

147

241

275

663

Reduced VOC emissions (kt)

562

51

156

769

Compliance costs (million $)

1,014

546

1,706

3,265

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

Consumer impacts

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

Competitiveness impacts

The proposed Regulations would impose compliance costs on oil and gas companies, which would divert resources from other productive uses. The impacts of the costs of regulatory compliance would 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 proposed Regulations would likely be small for producers of light oil and natural gas. It is expected that heavy oil producers would experience slightly higher financial impacts, because compliance costs represent a larger proportion of their current development costs relative to natural gas and light oil wells. As a consequence of the cost difference, heavy oil wells have a greater proportional impact on profitability.

Total compliance costs are estimated to be $3.3 billion over the period of analysis. In 2015, total capital and operating expenditures in the Western Canadian conventional oil and gas sector were $52 billion, the lowest level since 2009 and 3% 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 proposed Regulations would represent around 0.5% of cumulative industry expenditures ($700 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 facilities with lower production 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 proposed Regulations.

In response to the potential financial and competitiveness impacts of the proposed Regulations, several flexibilities have been included. For example, standards that would require significant capital investment, such as the facility production venting requirements and the pneumatic controller and pump requirements, would not come into force until 2023, giving firms lead time to adjust. The proposed Regulations would 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.

Potential competitiveness concerns posed by the proposed Regulations could be further offset by existing regulations in the United States and commitments from Mexico. The proposed Regulations are based on current U.S. source-by-source rules that apply to new and modified oil and gas facilities, which were finalized in 2012 and 2016.

Uncertainty of impact estimates

The discount rate used for this analysis is 3%, as recommended by TBS for environmental and health projects. TBS also recommends using a 7% discount rate for other cost-benefit analyses. A sensitivity analysis comparing the central case (3%) to a higher discount rate (7%) still yields an expected net benefit, as shown in Table 14.

Uncertainty is also associated with the values used to monetize the benefits from GHG emission reductions. For example, the central SCC value used in this cost-benefit analysis may not fully capture potential low-probability, high-impact outcomes due to climate change. To address this concern, the Department publishes a 95th percentile SCC value for sensitivity analyses, which attempts to capture the costs associated with low-probability, high-impact outcomes, including potential catastrophic impacts of climate change.

It is also possible that costs are higher than estimated and benefits are lower than estimated (e.g. if the value of conserved gas is significantly lower than the market price of natural gas), which would lower the estimated net benefits. Over the analysis time frame, estimated benefits were almost five times greater than costs (a benefit-to-cost ratio of 5:1). Thus, even if benefits were nearly five times smaller or costs were nearly five times larger than estimated, there would still be an expected net benefit. The Department has typically considered uncertainty ranges 50% higher or lower than the central case. Sensitivity analyses that considered these scenarios still yield expected net benefits, as shown in Table 14 below.

Table 14: Sensitivity analyses (millions of dollars)

Alternate Impact Analysis Estimates

Benefits
(B)

Costs
(C)

Net Benefits
(B – C)

Benefit-Cost Ratio
(B/C)

Central case (from table 11)

15,014

3,295

11,728

5:1

Benefits and costs discounted at 7% per year

9,488

2,384

7,104

4:1

GHGs valued using 95th percentile SCC/SCCH4

43,666

3,295

40,371

13:1

Reduced conserved gas benefit

13,429

3,295

10,134

4:1

Benefits 50% lower and costs 50% higher

7,507

4,927

2,580

2:1

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 would not change their behaviour in the absence of the proposed Regulations. There could be some “natural adoption” of lower-emitting equipment or practice without the proposed 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 proposed Regulations would be proportionally lower, which would still yield an expected net benefit.

“One-for-One” Rule

The proposed 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 would be approximately $1.1 million for all stakeholders, or $1,100 per company. (see footnote 46) In addition, the proposed Regulations would 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, as facilities would be required 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 mainly the record keeping of emissions of methane from the facility and the leak incidences. This is estimated to range from 15 minutes to 40 hours per company per year depending on the standard. (see footnote 47)

The other main driver (17%) of administrative costs is facility registration requirements. For each facility, regulatees would be required to register and send to the Minister a one-time registration report. 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. (see footnote 48)

Small business lens

It is estimated that the proposed Regulations would affect 57 874 oil and gas facilities, owned by 1 062 companies. Although the majority of facilities that would be covered by the proposed Regulations are owned by medium and large businesses, some facilities operated by small businesses would also be covered. Therefore, the proposed Regulations would trigger the small business lens. An estimated 579 facilities are owned by 475 small businesses.

To reduce costs associated with the proposed Regulations for small businesses, several regulatory design elements would be incorporated into the proposed Regulations (flexible option). Facilities operating with a potential to emit (PTE) under the 60 000 m3 threshold would be exempt from most of the facility-based requirements under the proposed Regulations. Since most small businesses own facilities that emit gaseous hydrocarbons less than the threshold, they would not be subject to the above-mentioned requirements, nor the associated record-keeping and reporting requirements. The proposed Regulations are expected to impact only about 23% of small businesses. The Regulatory Flexibility Analysis Statement below (table 15) shows the expected costs to small businesses under the initial and flexible options.

Table 15: 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

475

475

 

Annualized Value (see footnote *)

Present Value

Annualized Value (see footnote **)

Present Value

Compliance costs

$5,284,000

$69,566,000

$997,000

$13,126,000

Administrative costs

$128,000

$1,691,000

$73,000

$963,000

Total costs

$5,412,000

$71,257,000

$1,070,000

$14,089,000

Total cost per small business

$11,000

$150,000

$2,000

$30,000

Risk considerations:

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

In the 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 proposed 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 about $120,000 between 2018 and 2035 relative to the initial option under consideration, or about $9,000 per year. The proposed Regulations would result in cumulative costs of about $14 million for small businesses, or $30,000 per small business. While not part of this assessment, the design elements of the flexible option are expected to also reduce administrative and compliance costs for large businesses that own smaller facilities.

Consultation

Since April 2016, the Department has held over 150 hours of consultations with stakeholders and provincial partners on the proposed Regulations, 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 have participated.

The Department presented to stakeholders and provincial partners a description of a draft regulatory approach early in the consultation process, which included proposals to manage five emission sources using regulation, specific emission limits for significant emission sources, and anticipated compliance actions that could reduce methane emissions from each source. Three operational control measures (LDAR, compressors and well completions) were proposed to come into force in 2018, while two control measures requiring more substantial capital investment (facility venting limits and pneumatic device venting restrictions) were proposed to come into force in 2020. The proposed Regulations reflect feedback on this approach, ranging from broad changes in the timing of coming into force to requirements pertaining to specific emission sources.

Industry

The Department engaged in many discussions with industry representatives from the oil and gas sector. Some key stakeholders involved in these discussions were the Petroleum Services Association of Canada (PSAC), the Explorers and Producers Association of Canada (EPAC) and the Canadian Association of Petroleum Producers (CAPP). These representatives were supportive of the environmental objective of the draft approach and of the methane reduction targets announced by the Prime Minister. However, oil and gas sector representatives were concerned that the initial coming-into-force dates would not allow existing facilities enough lead time to comply and that it would be difficult for facilities to comply with all the control measures in the winter months. Furthermore, the oil and gas industry suggested that the well completion by hydraulic fracturing requirements should be written to be identical to that of existing provincial measures in British Columbia and Alberta. CAPP also presented an alternative proposal that advocated for less stringent standards.

The Department also met with companies who provide pollution prevention solutions to the oil and gas production sector. This industry was supportive of the proposed Regulations and noted that it would be able to quickly react to market demand. It noted that clean technology solutions are already in place and have been proven in the oil and gas sector.

In response to industry concerns, the Department changed the coming-into-force dates of the proposed Regulations to 2020 for LDAR, compressor and well completion by hydraulic fracturing requirements and to 2023 for facility production venting and pneumatic device requirements. In addition, the proposed Regulations would now require leak inspections three times per year to account for operational difficulties in the winter. The emission limit for reciprocating compressors was increased to reduce compliance costs. Finally, the well completions control measures were removed for the jurisdictions of British Columbia and Alberta because of their existing provincial requirements.

The oil and gas industry was satisfied with the modifications that the Department offered, but continue to challenge federal regulations on the sector.

Provincial and territorial governments

All provinces and territories, with the exception of Prince Edward Island and Nunavut, have participated in one or more consultation sessions. In general, provinces and territories have been supportive of the overall emission reduction goal but would like to ensure federal requirements are consistent with provincial climate change approaches. Most provinces with significant oil and gas activity (e.g. Alberta, British Columbia, Saskatchewan, Nova Scotia, and Newfoundland and Labrador) have been interested in better understanding the possibility of obtaining equivalency agreements under CEPA.

In response, the Department has committed to being as collaborative, open and transparent as possible with provincial partners and stakeholders. Numerous teleconferences and face-to-face meetings have been held, and information has been provided on an ongoing basis, including modelling data and analysis about the proposed regulatory approach; anticipated emission outcomes by jurisdictions; cost-benefit analysis methodology; opportunities around equivalency; and draft regulatory text.

Concerns were expressed regarding what was seen as “aggressive” federal regulatory timelines. The impact of the proposed Regulations on small oil and gas operators and on facilities located in isolated areas was raised. Other concerns included the potential impact on competitiveness if there were differences in regulatory approach, coverage and timelines between the United States and Canada.

In response to provincial and territorial concerns, the Department changed the coming-into-force dates of the proposed Regulations to 2020 and 2023 to allow for adequate time to negotiate equivalency agreements.

Additionally, Atlantic provinces were concerned about the potential for increased costs and operating challenges associated with implementing the proposed Regulations at offshore facilities. The Department held specific meetings with the provincial governments of Nova Scotia and Newfoundland and Labrador, and the offshore petroleum boards, (see footnote 49) to discuss these concerns.

As a result of these discussions, the proposed Regulations include certain flexibilities, for example extended repair timelines, for the offshore environment.

Overall, most provincial and territorial governments are supportive of the proposed Regulations and are satisfied with the modifications that the Department offered.

Environmental non-governmental organizations (ENGOs)

ENGOs were very supportive of the methane reduction target and its potential to contribute to international climate change goals. They welcomed federal regulations for the oil and gas sector and communicated a desire for consistency and transparency in the proposed Regulations. They asserted that reducing methane is the most cost-effective GHG reduction opportunity and presents an impactful approach to reaching Canada’s climate targets. Some key ENGOs involved in these consultations were the Clean Air Task Force (CATF), the Environmental Defense Fund (EDF) and the Pembina Institute. These groups provided the Department with an alternative proposal. There were some concerns about the level of stringency and lack of annual reporting and its impact on assessing industry compliance.

Consequently, 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 per year. 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 has extensive record-keeping requirements in the proposed Regulations and would be able to require reporting when needed.

Overall, ENGOs are supportive of the proposed Regulations.

Indigenous peoples

The Inuit Tapiriit Kanatami and the Indian Resource Council were consulted on the draft approach and showed support for the environmental objectives of the proposed Regulations. No significant major concerns were raised.

Consultation summary

After consultations with stakeholders and provincial partners, the Department made changes to the proposed Regulations in order to address any identified concerns, where feasible. In particular, the main change incorporated into the proposed Regulations was to delay the coming-into-force dates of the proposed standards to provide more lead time for existing facilities to be able to comply. Further adjustments to the proposed Regulations may be necessary to improve the text of the draft Regulations and apply technical clarifications depending on stakeholder comments to be received following publication in the Canada Gazette, Part I.

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 addition, Canada and the United States have a long and successful history of working together to reduce air emissions. Building on this success, a commitment to take action to address methane emissions from the oil and gas sector was formed in early 2016. In mid-2016, Mexico joined the United States and Canada in their commitment to reduce methane emissions from the oil and gas sector by 40% to 45% below 2012 levels by 2025. Presently, all three countries have committed to publish their respective federal regulations as soon as possible, and to work collaboratively on programs, policies and strategies. 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.

In recognition of the integrated nature of the North American energy market, Canada intends to cover emissions from the same sources subject to current U.S. regulatory requirements. These sources include facility production venting, LDAR, well completion by hydraulic fracturing, pneumatics and compressors. The structure of the proposed 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.

Existing facilities

The proposed Regulations would cover all facilities, whereas the U.S. EPA’s new source performance standards (NSPS) cover only 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 proposed Regulations would not come into force in Canada until after 2020, the U.S. sector would have been facing similar requirements for a decade, and most of the facilities would 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 would not be immediately captured, which would make it difficult to meet the methane reduction targets announced by the Prime Minister.

Industry administrative burden

The current U.S. approach to regulating the oil and gas sector requires facilities to conduct a substantial number of administrative tasks. The proposed Regulations differ from the NSPS in order to meet commitments in Canada’s Cabinet Directive on Regulatory Management to control the administrative burden of regulations on business. For example, the NSPS require facilities to report information on specific technical details annually. In order to minimize the administrative burden, the proposed Regulations require on-demand reporting.

Avoided regulatory overlap with 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, and recognizing that a significant share of the compliance costs would 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 proposed Regulations to the extent possible. For example, the proposed 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, since these jurisdictions already have adequate measures in place.

Unique Canadian product types

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

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. The latest emissions data indicates that the GHG emissions from production and processing activities in 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 2017 and 2035, which represents a significant portion of Canada’s overall GHG emissions (726 Mt in 2013).

Canada and its international partners agreed to work together to implement the Paris Agreement, to limit the temperature rise this century to well below 2 °C. Canada has also committed to a joint approach on climate change with the United States and Mexico. The three countries committed to introducing or expanding federal regulations to reduce methane emissions from oil and gas facilities.

It is expected that the proposed Regulations would lead to a 20 Mt reduction in CO2e emissions in 2030, an estimated 7% contribution to Canada’s GHG emissions reduction target under the Paris Agreement. It is also expected that the proposed Regulations would lead to a 21 Mt reduction in methane emissions in 2025, a reduction of 41% below 2012 levels, falling in the range of a 40% to 45% reduction as committed in March 2016.

Between 2018 and 2035, the cumulative GHG emission reductions attributable to the proposed Regulations are estimated to be approximately 282 Mt. Avoided climate change damages associated with these reductions are valued at $13.4 billion. The proposed Regulations would also result in a co-benefit of 663 PJ of conserved gas with a market value of $1.6 billion, for total monetized benefits of $15.0 billion. The total cost of the proposed Regulations is estimated to be $3.3 billion, which would be offset in part by the recovery of 663 PJ (see footnote 50) of natural gas, with a market value of $1.6 billion, resulting in expected net benefits of $11.7 billion.

Since April 2016, the Department has held over 150 hours of consultations on the proposed Regulations with industry, provinces, territories, environmental organizations and associations of Indigenous peoples. Industry has expressed concerns with the potential competitiveness impacts that the proposed Regulations might have on Canada’s oil and gas sector, while environmental organizations expressed some concerns about the lack of annual reporting and its impact on assessing industry compliance. The Department has worked with stakeholders to minimize negative impacts, and these groups have been generally supportive of the environmental objective of the proposed Regulations.

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

Strategic environmental assessment

The proposed Regulations have been developed under Canada’s Clean Air Regulatory Agenda (CARA). A strategic environmental assessment (SEA) was completed for CARA in 2012 and a public statement was issued in 2013. (see footnote 51) That SEA concluded that activities under CARA would support the Federal Sustainable Development Strategy (FSDS) climate change goal to reduce GHGs. A SEA has also been conducted for the proposed Regulations, which confirms that this regulatory initiative supports the FSDS goal to reduce GHGs.

Implementation, enforcement and service standards

Depending on the standard, the proposed Regulations would come into force on January 1, 2020, or January 1, 2023. The proposed Regulations would be made under CEPA, and enforcement officers would, when verifying compliance, apply the Compliance and Enforcement Policy for CEPA. (see footnote 52) The Policy sets out the range of possible enforcement responses to alleged violations. Following an inspection or investigation, when an enforcement officer discovers an alleged violation, the officer would 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 proposed Regulations includes developing and posting compliance promotion information such as frequently asked questions (FAQs) on the Department’s website, as well as undertaking various outreach activities such as workshops and informational sessions. The Department would also respond to all inquiries sent by stakeholders to ensure that the requirements of the proposed 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 proposed Regulations, compliance promotion activities are expected to decline to a maintenance level. The compliance promotion activities would be adjusted according to compliance analyses or if unforeseen compliance challenges arise.

The Department, in its administration of the regulatory program, would provide services and would 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 would 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 proposed Regulations are directly related to international and domestic priorities to reduce methane emissions from the oil and gas industry by 40% to 45% from 2012 levels by 2025. The performance of the proposed Regulations in achieving these outcomes would be measured and evaluated.

Clear and quantified performance indicators would be defined for each outcome. For oil and gas facilities, these indicators include facility registration, permit applications and reported emission data on methane. Collected methane emission data would include venting and fugitive emissions. Performance would be tracked through annual or on demand reporting requirements as well as through enforcement activities. In addition, a compliance assessment would be conducted periodically to gauge the performance of every indicator against the identified targets. Regular review and evaluation of these performance indicators would allow the Department to detail the impacts of the proposed Regulations on the oil and gas sector and to evaluate the performance of the proposed Regulations in reaching the intended targets.

Contacts

Mark Cauchi
Executive Director
Oil, Gas and Alternate 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

Joe Devlin
Senior Economist
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

PROPOSED REGULATORY TEXT

Notice is given, pursuant to subsection 332(1) (see footnote a) of the Canadian Environmental Protection Act, 1999 (see footnote b), that the Governor in Council, pursuant to subsection 93(1), section 286.1 (see footnote c) and subsection 330(3.2) (see footnote d) of that Act, proposes to make the annexed Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector).

Any person may, within 60 days after the date of publication of this notice, file with the Minister of the Environment comments with respect to the proposed Regulations or a notice of objection requesting that a board of review be established under section 333 of that Act and stating the reasons for the objection. All comments and notices must cite the Canada Gazette, Part I, and the date of publication of this notice, and be sent by mail to the Oil, Gas and Alternative Energy Division, Department of the Environment, Gatineau, Quebec K1A 0H3 or by email to ec.methane-methane.ec@canada.ca.

A person who provides information to the Minister of the Environment may submit with the information a request for confidentiality under section 313 of that Act.

Ottawa, April 13, 2017

Jurica Čapkun
Assistant Clerk of the Privy Council

TABLE OF PROVISIONS

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

Purpose and Overview

1 Protection of environment and reduction of harmful effects

Interpretation

2 Definitions

Responsibility

3 Operator

General Requirements
Hydrocarbon Gas Conservation and Destruction Equipment

4 Hydrocarbon gas conservation equipment

5 Records — hydrocarbon gas conservation equipment

6 Hydrocarbon gas destruction equipment

7 Records — hydrocarbon gas destruction equipment

Well Completion by Hydraulic Fracturing

8 Application

9 Records — hydraulic fracturing

10 Non-application — B.C. and Alta.

Compressors

11 Capture or vent emissions — installation date

12 Measurement of flow rate of emissions

13 Compressor — flow rate limit

14 Records — compressor vents

Conditional Requirements
Conditions

15 Application of sections 19 to 33

16 Records — non-application

17 Records — first month of application

Determination of Volume of Gas

18 Documents containing applicable methods

Venting Limit

19 250 standard m3/month

20 Records — volumes of hydrocarbon gas

Leak Detection and Repair Program

21 Inspections

22 Application — other types of instruments

23 Leaks

24 Period for repair

25 Records

Pneumatic Controllers and Pneumatic Pumps

26 Pneumatic controllers — compressors ≥ 745 kW

27 Records — pneumatic controllers

28 Pneumatic Pumps

29 Non-application — conservation or destruction equipment

30 Permit — pneumatic pumps

Other Equipment

31 Pipes and hatches

32 Sampling systems and pressure relief devices

Revocation of Permit or Approval

33 Subsection 22(2) or 30(2)

Administration
Registration

34 Registration report

Record-making and Keeping of Documents

35 Records — deadline

36 SOR/2012-134

Coming into Force

37 January 1, 2020

SCHEDULE 1

SCHEDULE 2

SCHEDULE 3

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

  • (a) impose certain requirements on the oil and gas sector in order to reduce emissions of methane and certain volatile organic compounds; and
  • (b) designate the contravention of certain of its provisions as serious offences by adding them to the schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999).

Interpretation

Definitions

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

Act means the Canadian Environmental Protection Act, 1999. (Loi)

authorized official means

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

completion means the process of making a well ready for production, including such a process that involves hydraulic fracturing. (complétion)

conserve, in relation to hydrocarbon gas, means to recover hydrocarbon gas for use as fuel, for sale or for injection into an underground geological deposit that is for a purpose other than to dispose of the gas as waste. (conservation)

deliver means to transport hydrocarbon gas from an upstream oil and gas facility for a purpose other than to dispose of the gas as waste. (livrer)

design bleed rate means the rate, expressed in standard m3/h, at which gas is expected, according to the manufacturer of a pneumatic controller, to be continuously emitted from the pneumatic controller while it operates at a given operational setting specified by the manufacturer. (taux de purge nominal)

destroy means to convert hydrocarbons contained in hydrocarbon gas to carbon dioxide, along with other molecules, for a purpose other than to produce energy, and includes the flaring of hydrocarbon gas. (détruire)

EPA Method 21 means the method of the Environmental Protection Agency of the United States entitled Method 21 — Determination of Volatile Organic Compound Leaks, set out in Appendix A-7 to Part 60 of Title 40, Chapter I of the Code of Federal Regulations of the United States. (méthode 21 de l’EPA)

equipment component means a component of equipment at an upstream oil and gas facility that comes into contact with hydrocarbons and that has the potential to emit hydrocarbon gas. (composant d’équipement)

flowback means the process of recovering fluids, or fluids mixed with solids, that were injected into a well during hydraulic fracturing in order

  • (a) to prepare for further hydraulic fracturing;
  • (b) to prepare for cleanup of the well; or
  • (c) to initiate or resume production from the well. (reflux)

gas-to-oil ratio means the ratio of the volume of hydrocarbon gas produced, expressed in standard m3, to the volume of hydrocarbon liquid produced, expressed in standard m3. (rapport gaz-pétrole)

hydraulic fracturing means the process of injecting fluids, or fluids mixed with solids, under pressure into a well in order to create fractures in an underground geological reservoir through which hydrocarbons and other fluids can migrate toward the well and includes hydraulic refracturing, namely, hydraulic fracturing at a well that has previously undergone hydraulic fracturing. (fracturation hydraulique)

hydrocarbon means methane, which has the molecular formula CH4, or a volatile organic compound referred to in item 65 of the List of Toxic Substances in Schedule 1 to the Act. (hydrocarbures)

operator means a person who has the charge, management or control of an upstream oil and gas facility. (exploitant)

pneumatic controller means a device that uses pressurized gas to generate mechanical energy for the purpose of controlling or monitoring the conditions under which a process is carried out. (régulateur pneumatique)

pneumatic pump means a device that uses pressurized gas to generate mechanical energy for the purpose of pumping liquid. (pompe pneumatique)

ppmv means parts per million by volume. (ppmv)

primary processing means any processing of hydrocarbons that is for the principal purpose of removing any of, or any combination of, the following:

  • (a) water;
  • (b) hydrocarbon liquids;
  • (c) sulphur compounds; and
  • (d) contaminants. (traitement primaire)

produce, in relation to hydrocarbon gas or liquid, means to extract hydrocarbon gas or liquid from an underground geological deposit or reservoir. (production)

receive, in relation to hydrocarbon gas, means to receive at an upstream oil and gas facility, other than from a natural source, hydrocarbon gas

  • (a) that is raw; or
  • (b) that has undergone primary processing without having been subject to additional processing. (recevoir)

standard conditions means a temperature of 15°C and a pressure of 101.325 kPa. (conditions normalisées)

standard m3 means a cubic metre of gas at standard conditions. (m3 normalisé)

upstream oil and gas facility means the buildings, other structures and stationary equipment — that are located on a single site, on contiguous or adjacent sites or on sites that form a network in which a central processing site is connected by gathering pipeline with one or more well sites — that function together in an integrated manner for the purpose of

  • (a) the extraction of hydrocarbons from an underground geological deposit or reservoir;
  • (b) the primary processing of those hydrocarbons; or
  • (c) the transportation of hydrocarbons — including their storage for transportation purposes — other than for local distribution. (installation de pétrole et de gaz en amont)

venting means the emission of hydrocarbon gas from an upstream oil and gas facility in a controlled manner, other than the emission of gas arising from combustion, due to

  • (a) the design of equipment or operational procedures at the facility; or
  • (b) the occurrence of an event that pressurizes the gas beyond the capacity of the equipment at the facility to retain the gas. (évacuation)

well includes a well drilled to allow for the injection of fluids or fluids mixed with solids. (puits)

Interpretation of documents incorporated by reference

(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 of 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.

General Requirements

Hydrocarbon Gas Conservation and Destruction Equipment
Hydrocarbon gas conservation equipment

4 Hydrocarbon gas conservation equipment that is used at an upstream oil and gas facility must

  • (a) be operated in such a manner that at least 95% of the hydrocarbon gas that is routed to the equipment — based on a calculation of the volumetric flow rates at standard conditions — is captured and conserved;
  • (b) be operating continuously, other than during periods when it is undergoing normal servicing or timely repairs; and
  • (c) be used and maintained in accordance with the applicable recommendations of its manufacturer.
Records — hydrocarbon gas conservation equipment

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

  • (a) for each month during which the equipment is used, of the percentage, at any given moment, of the hydrocarbon gas routed to the equipment that is captured and conserved, along with a calculation of the volumetric flow rates on which that percentage is based, with supporting documents; and
  • (b) of the equipment’s operations and any maintenance of the equipment, along with an indication, with supporting documents, as to whether the equipment was used and maintained in accordance with the applicable recommendations of its manufacturer.
Hydrocarbon gas destruction equipment

6 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

  • (a) Sections 3.6 and 7 of Version 4.5 of the guideline entitled Flaring and Venting Reduction Guideline, published by the Oil and Gas Commission of British Columbia in June 2016, if the facility is located in British Columbia;
  • (b) section 3 of the directive entitled Directive S-20: Saskatchewan Upstream Flaring and Incineration Requirements, published by the Government of Saskatchewan on November 1, 2015, if the facility is located in Saskatchewan;
  • (c) the authorization — issued by the Canada-Nova Scotia Offshore Petroleum Board or the Canada– Newfoundland and Labrador Offshore Petroleum Board, as the case may be — with respect to the venting and the flaring of emissions by the facility, if the facility is located offshore; and
  • (d) sections 3.6 and 7 of Directive 060 entitled Upstream Petroleum Industry, Flaring, Incinerating, and Venting, published by the Alberta Energy Regulator on March 22, 2016, in any other case.
Records — hydrocarbon gas destruction equipment

7 A record in respect of any hydrocarbon gas destruction equipment used at an upstream oil and gas facility must be made of information, with supporting documents, that demonstrates that the requirements related to the destruction of hydrocarbon gas set out in the applicable document referred to in section 6 are satisfied.

Well Completion by Hydraulic Fracturing

Application

8 (1) This section applies to 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 in 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.

Records — hydraulic fracturing

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

  • (a) of the gas-to-oil ratio, based on the most recent determination of the gas-to-oil ratio prior to the hydraulic fracturing; and
  • (b) if that gas-to-oil ratio is at least 53:1, of information, with supporting documents, that demonstrates that the hydrocarbon gas associated with flowback were captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.
Non-application — B.C. and Alta.

10 Sections 8 and 9 do not apply in respect of an upstream oil and gas facility that is located in British Columbia or Alberta.

Compressors

Capture or vent emissions — installation date

11 The emissions of hydrocarbon gas from the seals of a centrifugal compressor, or from the rod packings of a reciprocating compressor, at an upstream oil and gas facility must

  • (a) if the compressor is installed on or after January 1, 2020, be captured and routed to hydrocarbon gas conservation equipment; and
  • (b) if the compressor is installed before January 1, 2020, be
    • (i) captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment, or
    • (ii) routed to a vent.

Measurement of flow rate of emissions

12 (1) The flow rate of emissions of hydrocarbon gas from a vent referred to in subparagraph 11(b)(ii) must be measured — at operating conditions that are representative of the compressor’s normal operating conditions during the 90 days before the measurement is taken — by means of a flow meter that is calibrated in accordance with subsection (2) and has a calibration error within 5% of the reference value.

Calibration

(2) The calibration of the flow meter must be carried out in accordance with a standard or method published by

  • (a) a government of any state or of a subdivision of any state, or any institution of such a state or subdivision;
  • (b) an international organization of states or an international organization that is established by the governments of states, or any institution of one of those international organizations; or
  • (c) an organization that develops standards or methods based on consensus and that is internationally recognized as being competent to establish that standard or method.

Initial and subsequent measurements

(3) The flow rate must be measured

  • (a) initially by January 1, 2021, if the compressor was installed at the facility before January 1, 2020; and
  • (b) subsequently, within 365 days after the day on which a previous measurement was taken.

Compressor — flow rate limit

13 (1) If the flow rate of emissions of hydrocarbon gas from a vent, measured in accordance with subsection 12(1), is greater than the following limit, corrective action must be taken to reduce that flow rate below or equal to that limit, as demonstrated by a remeasurement:

  • (a) in the case that the emissions are from the seals of a centrifugal compressor, the product of 0.17 standard m3/min and the number of those seals; and
  • (b) in the case that the emissions are from the rod packings of a reciprocating compressor, the product of 0.023 standard m3/min and the number of those rod packings.

Remeasurement

(2) The remeasurement must be taken in accordance with subsection 12(1) by the later of

  • (a) the day that is
    • (i) in the case that the emissions are from the seals of a centrifugal compressor, the 90th day after the day on which the most recent measurement is taken under subsection 12(3), and
    • (ii) in the case that the emissions are from the rod packings of a reciprocating compressor, the 30th day after the day on which the most recent measurement is taken under subsection 12(3), and
  • (b) the day on which the compressor is started up after its next planned shutdown, in the case that the volume of hydrocarbon gas at standard conditions that would be emitted if the hydrocarbon gas in the compressor were purged in order to take the corrective action is greater than the estimated volume of hydrocarbon gas that would, since the day referred to in paragraph (a), be emitted until that next planned shutdown if no corrective action were taken.

Estimated volume

  • (3) The estimated volume of hydrocarbon gas must be based on the most recent measurement of the flow rate of emissions taken under subsection 12(3) from the vent.

Precision

(4) If there is no measurement of the flow rate of emissions from a vent on which to base an estimation referred to in subsection (3), a measurement of the flow rate of emissions from the vent must be taken in accordance with subsection 12(1).

Records — compressor vents

14 A record , in respect of each vent referred to in subsection 12(1), must be made of

  • (a) for each measurement, including a remeasurement, of the flow rate of emissions from the vent,
    • (i) the serial number of the compressor, along with its make and model,
    • (ii) the measured flow rate,
    • (iii) the date on which the measurement was taken,
    • (iv) the standard or method in accordance with which the flow meter used for the measurement was calibrated, including the name of the entity that published it and the relevant provisions of the standard or method, and
    • (v) the name of the person who took the measurement and, if that person is a corporation, the name of the individual who made it; and
  • (b) for each of those measurements that led to the taking of corrective action,
    • (i) a description of the corrective action,
    • (ii) the dates on which that corrective action was taken, and
    • (iii) for each corrective action in relation to a compressor, the volume and estimated volume, determined for the purpose of paragraph 13(2)(b), along with supporting calculations.

Conditional Requirements

Conditions

Application of sections 19 to 33

15 (1) Sections 19 to 33 apply in respect of an upstream oil and gas facility as of the beginning of the first month of the first 12-month period during which the facility produces and receive a combined volume of more than 60 000 standard m3 of hydrocarbon gas determined as follows:

  • (a) the greatest combined volume, based on records, of hydrocarbon gas produced and received at the facility during any period of 12 consecutive months within the 60-month period before that first month, if there are records indicating that volume for at least one of those periods of 12 consecutive months;
  • (b) the volume that is the product of 12 and the monthly average combined volume, based on records, of hydrocarbon gas produced and received at the facility, if there are records indicating that volume for at least one month within that 60-month period but there are no records of that volume for any of those periods of 12 consecutive months; and
  • (c) the combined volume of hydrocarbon gas that expected to be produced and received at the facility for the 12-month period after that first month, as determined in accordance with the applicable method set out in section 18, in any other case.

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 18.

Records — non-application

16 If none of sections 19 to 33 apply, for a given month, in respect of an upstream oil and gas facility, a record, with supporting documents, must be made

  • (a) of the gas-to-oil ratio and the volume of the hydrocarbon liquid produced or expected to be produced, expressed in standard m3, during the given month;
  • (b) of the combined volume of hydrocarbon gas produced and received referred to in paragraph 15(1)(a) or (b) or of the combined volume referred to in paragraph 15(1)(c), as the case may be; and
  • (c) for a well at the facility that undergoes well completion during the given month, of the volume expected to be produced by the well referred to in subsection 15(2).

Records — first month of application

17 A record must be made of the following information in respect of the first month as of which an upstream oil and gas facility produces and receives a combined volume of more than 60 000 standard m3 of hydrocarbon gas as determined in accordance with subsection 15(1):

  • (a) the month and the calendar year in which it occurs; and
  • (b) the combined volume of hydrocarbon gas produced and received referred to in paragraph 15(1)(a) or (b) or the combined volume referred to in paragraph 15(1)(c), as the case may be.

Determination of Volume of Gas

Documents containing applicable methods

18 (1) For the purpose of sections 15 and 19, 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

  • (a) the document entitled Measurement Guideline for Upstream Oil and Gas Operations, published by the Oil and Gas Commission of British Columbia on June 1, 2013, if the facility is located in British Columbia;
  • (b) the document entitled Measurement Requirements for Oil and Gas Operations and commonly referred to as Directive PNG017, published by the Government of Saskatchewan on Apri1 1, 2016 (version 2.0), if the facility is located in Saskatchewan;
  • (c) the document entitled Measurement Guidelines under the Newfoundland and Labrador and Nova Scotia Offshore Areas Drilling and Production Regulations published jointly by the Canada–Newfoundland and Labrador Offshore Petroleum Board and the Canada-Nova Scotia Offshore Petroleum Board in September 2011, if the facility is located offshore; and
  • (d) the document entitled Measurement Requirements for Oil and Gas Operations and commonly referred to as AER Directive 017, published by the Alberta Energy Regulator on March 31, 2016, in any other case.

Directives PNG017 and AER 017 — section 12.2.2

(2) In Section 12.2.2 of the Saskatchewan Directive PNG017 and of the AER Directive 017 the reference to “ volume exceeding 2.0 103 m3/day ” is to be read as “ volume exceeding 500 m3/day ”.

Venting Limit

250 standard m3/month

19 (1) An upstream oil and gas facility must not, for any month other than an excluded month, vent more than 250 standard m3 of hydrocarbon gas unless the venting is required to respond to an emergency situation by avoiding the threat of significant damage or injury, or death.

Notification of emergency

(2) An operator for the upstream oil and gas facility must, as soon as feasible, notify the Minister in writing of any venting in an emergency situation, along with the following information:

  • (a) the information referred to in section 4 of Schedule 3;
  • (b) an indication of the volume of hydrocarbon gas vented, expressed in standard m3; and
  • (c) a description of the emergency situation.

Excluded month

(3) A month is excluded if an operator for the facility demonstrates that — for the 12 consecutive months before the month — the combined volume of hydrocarbon gas that were vented or destroyed at, or delivered from, the facility was less than 40 000 standard m3.

Records — volumes of hydrocarbon gas

20 (1) For each month that an upstream oil and gas facility is subject to subsection 19(1), a record, with supporting documents, must be made of

  • (a) the volume of hydrocarbon gas produced at the facility, expressed in standard m3, along with the gas-to-oil ratio and the volume of hydrocarbon liquid produced, expressed in standard m3;
  • (b) the volume of hydrocarbon gas received at the facility, expressed in standard m3; and
  • (c) the volume of hydrocarbon gas vented at the facility, expressed in standard m3.

Records — excluded months

  • (2) For each month excluded under subsection 19(3), a record, with supporting documents, must — for each month during which the facility operated in the 12 consecutive months before the month — be made of the volume of hydrocarbon gas vented or destroyed at, or delivered from, the facility.

Leak Detection and Repair Program

Inspections

21 (1) An equipment component at an upstream oil and gas facility — other than a facility that consists only of a single wellhead with gathering pipelines connected to it — that operates for at least one day in a four-month period must be inspected for the release of hydrocarbons by means of an eligible leak detection instrument every four months and at least 60 days after a previous inspection.

Eligible leak detection instruments

(2) The following leak detection instruments are eligible:

  • (a) a portable monitoring instrument if it
    • (i) meets the specifications set out in Section 6 of EPA Method 21,
    • (ii) is operated in accordance with the requirements of Section 8.3 of EPA Method 21 to the extent those requirements are consistent with its manufacturer’s recommendations,
    • (iii) is calibrated in accordance with Sections 7, 8.1, 8.2 and 10 of EPA Method 21 before it is used, for each day on which it is used, and
    • (iv) undergoes a calibration drift assessment after its last use on each of those days in accordance with the requirements set out in Section 60.485a(b)(2) of Subpart VVa, entitled Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006, in Part 60 of Title 40, Chapter I of the Code of Federal Regulations of the United States;
  • (b) an optical gas-imaging instrument if it is capable of imaging gas that is
    • (i) in the spectral range for the compound of highest concentration in the hydrocarbon gas to be measured,
    • (ii) half methane and half propane at a total concentration of at most 500 ppmv and at a flow rate of at least 60 g/h leaking from an orifice that is 0.635 cm in diameter, and
    • (iii) at the viewing distance determined in accordance with the requirements of the alternative work practice of the Environmental Protection Agency of the United States set out in Sections 60.18(h)(7)(i)(2)(i) to (v) of Section 60.18, entitled General control device and work practice requirements, in Part 60 of Title 40, Chapter I of the Code of Federal Regulations of the United States; and
  • (c) another type of instrument whose use at the facility has been approved by the Minister on application by an operator for the facility.

Operation and maintenance

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

Training

(4) The inspection referred to in subsection (1) must be conducted by an individual who, not more than five years before the inspection, has received training in

  • (a) the operation and maintenance, in accordance with subsection (3), of eligible leak detection instruments; and
  • (b) the calibration requirements
    • (i) set out in subparagraphs (2)(a)(iii) and (iv) for eligible portable monitoring instruments, and
    • (ii) set out in the Minister’s approval under subsection 22(2) for other types of eligible leak detection instruments, if the approval includes calibration requirements.

Application — other types of instruments

22 (1) The application referred to in paragraph 21(2)(c) must

  • (a) include the information that was provided for the purpose of obtaining the approval, along with a document attesting to that approval, if the other type of instrument has been approved for use in detecting a leak of hydrocarbons
    • (i) under Sections 60.5398a and 60.5402a of Subpart OOOOa entitled Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After September 18, 2015, in Part 60 of Title 40, Chapter I of the Code of Federal Regulations of the United States, or
    • (ii) under any other provision, by a government of any state or of a subdivision of any state, or any institution of such a state or subdivision; and
  • (b) in any other case, based on information obtained by the operator over a period of at least 12 consecutive months, include
    • (i) an indication of the smallest quantity of hydrocarbons that the instrument is capable of detecting as a leak, including a demonstration of that capability based on a range of operating conditions that are normal at the facility,
    • (ii) a description of the technology or process used by the instrument to detect leaks, including a description of any conditions on its use,
    • (iii) a description of how the instrument is used,
    • (iv) an indication of the repeatability of the instrument for the detection of leaks,
    • (v) the number and frequency of results obtained from the measurement of leaks,
    • (vi) an indication of bias in those results, and
    • (vii) a demonstration that the instrument is capable of detecting a leak of hydrocarbons that is detectable by an optical gas-imaging instrument and has at least the degree of repeatability of an optical gas-imaging instrument.

Approval

  • (2) The Minister must grant the application and approve the use of the leak detection instrument at the facility — with any modification, or subject to any conditions, that the Minister considers desirable — if the Minister is of the opinion, based on the information provided with the application, that the instrument, when used in the manner as approved, is capable of detecting a leak of hydrocarbons that is detectable by an optical gas-imaging instrument and has at least the degree of repeatability of an optical gas-imaging instrument.

Approval — informing applicant

(3) Without delay after approving the use of the other leak detection instrument, the Minister must inform the applicant of the approval.

Environmental Registry

(4) The Minister must maintain a list of leak detection instruments, as approved under this section, and make it publicly available on the Environmental Registry established under section 12 of the Act.

Refusal

(5) The Minister must refuse the application if the Minister

  • (a) is of the opinion that the information provided with the application is not adequate to determine whether the instrument is capable of detecting a leak of hydrocarbons that is detectable by an optical gas-imaging instrument and has at least the degree of repeatability of an optical gas-imaging instrument; or
  • (b) has reasonable grounds to believe that the applicant has provided false, misleading or incomplete information in the application.

Refusal — informing applicant

(6) Without delay after refusing the application, the Minister must inform the applicant of the refusal, along with the reasons for it.

Leaks

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

  • (a) the release consists of at least 500 ppmv of hydrocarbons, as determined by an inspection conducted by means of an eligible portable monitoring instrument in accordance with EPA Method 21; or
  • (b) the release is detected
    • (i) during an inspection conducted by means of an eligible optical gas-imaging instrument,
    • (ii) during an inspection conducted by means of another eligible instrument referred to in paragraph 21(2)(c), or
    • (iii) by means of an auditory method, an olfactory method or a visual method, including the observation of the dripping of hydrocarbon liquids from the equipment component.

Release not considered a leak

  • (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

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

  • (a) if the repair can be carried out while the equipment component is operating, within 30 days after the day on which it was detected;
  • (b) if the equipment component — other than an equipment component that can be repaired while it is operating — is at a facility that is located offshore, within 365 days after the day on which it was detected; and
  • (c) in any other case, by the end of the next planned shutdown.

Next shutdown

  • (2) The next shutdown referred to in subparagraph (1)(b)(ii) must be scheduled not later than the date on which the volume of hydrocarbon gas at standard conditions that would be emitted if the hydrocarbon gas in the equipment component were purged in order to carry out the repair is equal to the estimated volume of hydrocarbon gas that would, since the day on which the leak was detected, be emitted until that next shutdown if no repair were made.

Repair

(3) A leak is considered to be repaired if

  • (a) the equipment component is inspected by means of an eligible portable monitoring instrument in accordance with EPA Method 21; and
  • (b) the release is determined to consist of less than 500 ppmv of hydrocarbons.

Records

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

  • (a) for each other type of leak detection instrument that was approved further to an application that included information referred to in paragraph 22(1)(b), the information obtained over a period of at least 12 consecutive months on which the application for the approval of the use of instrument was based;
  • (b) for each calibration of an eligible leak detection instrument,
    • (i) the dates of the calibration,
    • (ii) the result of each calibration drift assessment, and
    • (iii) the name, job title, if any, and address of the individual who carried out the calibration;
  • (c) for each inspection of an equipment component,
    • (i) the date of the inspection , along with the name of the individual who conducted it,
    • (ii) the type of equipment component,
    • (iii) the location of the equipment component within the facility or the Global Positioning System (GPS) coordinates of the equipment component,
    • (iv) the type of leak detection instrument used to conduct the inspection, including, if any, its make and model,
    • (v) in the case that an optical gas-imaging instrument referred to in paragraph 21(2)(b) was used to conduct the inspection, the images recorded with an embedded indication of the date and time when they were recorded, along with the GPS coordinates of the place where they were recorded,
    • (vi) in the case that another type of instrument referred to in paragraph 21(2)(c) was used to conduct the inspection, the information obtained as a result of the inspection, along with the date and time when, and the GPS coordinates of the place where, the information was obtained, and
    • (vii) in the case that an inspection resulted in the detection of a leak, an indication of the means, among those set out in subsection 23(1), by which the leak was detected and, in the case of a leak detected by a means set out in paragraph 23(1)(b), an indication as to whether the release was determined in accordance with subsection 23(2) to consist of less than 500 ppmv and, if so, the date of that determination, the name of the person who made that determination — and if that person is a corporation, the name of the individual who made it — and its result, expressed in ppmv, along with the make and model, if any, of the instrument used to make that determination;
  • (d) for each leak detected by a means set out in subparagraph 23(1)(b)(iii) that was not as a result of an inspection,
    • (i) the date on which the leak was detected, along with the name of the individual who detected it,
    • (ii) the type of equipment component,
    • (iii) the location of the equipment component within the facility or the GPS coordinates of the equipment component, and
    • (iv) an indication as to whether the release was determined in accordance with subsection 23(2) to consist of less than 500 ppmv and, if so, the date of that determination, the name of the person who made that determination — and if that person is a corporation, the name of the individual who made it — and its result, expressed in ppmv, along with the make and model, if any, of the instrument used to make that determination;
  • (e) for each individual who conducted an inspection and who received training in the operation and maintenance or in the calibration of leak detection instruments,
    • (i) their name, along with the name and business address of their employer, if their employer is not the operator,
    • (ii) the name and business address of the entity that provided the training, along with the name and job title of the individuals who provided it,
    • (iii) the dates on which the training was provided and, for each of those dates, the number of hours of training, and
    • (iv) a description of the training;
  • (f) for each repair of a leak from an equipment component,
    • (i) a description of the steps that were taken to repair the leak, along with the dates on which those steps were taken, and
    • (ii) the result, expressed in ppmv, of the inspection by means of an eligible portable monitoring system in accordance with EPA Method 21, along with the date on which that result was obtained; and
  • (g) the following information related to a repair that was not carried out within 30 days of the detection of the leak:
    • (i) an indication as to why the equipment component could not be repaired while it was operating, and
    • (ii) if applicable, the date determined in accordance with subsection 24(2), along with the information and calculation on which that determination was based.

Document-keeping

(2) A copy of the following documents must be kept:

  • (a) each recommendation of the manufacturer for the operation and maintenance of each eligible leak detection instrument used; and
  • (b) each approval under subsection 22(2).

Pneumatic Controllers and Pneumatic Pumps

Pneumatic controllers — compressors ≥ 745 kW

26 (1) A pneumatic controller at an upstream oil and gas facility must not function using hydrocarbon gas, if the sum of the rated power of the compressors that are used at the facility is 745 kW or more.

Pneumatic controllers — compressors < 745 kW

(2) If the sum of the rated power of the compressors that are used at the facility is less than 745 kW, a pneumatic controller that is used at the facility must not function using hydrocarbon gas, unless it is operated at an operational setting specified by the manufacturer such that its design bleed rate for that operational setting is less than or equal to 0.17 standard m3/h.

Non-application — pneumatic controllers

(3) Subsections (1) and (2) do not apply in respect of a pneumatic controller for a calendar year if an operator for the facility at which the pneumatic controller is used provides the Minister with the information in respect of the calendar year set out in Schedule 1, along with information that establishes that, because of the need for the pneumatic controller to have an adequate response time to control a process in the facility’s production activities,

  • (a) a pneumatic controller referred to in subsection (1) must function using hydrocarbon gas; and
  • (b) a pneumatic controller referred to in subsection (2) must operate at an operational setting specified by the manufacturer such that its design bleed rate for that operational setting is more than 0.17 standard m3/h.

Records — pneumatic controllers

27 A record , in respect of each pneumatic controller used at an upstream oil and gas facility that functions using hydrocarbon gas and that is subject to subsection 26(2) must be made of

  • (a) the identifier for the pneumatic controller;
  • (b) an indication as to whether the pneumatic controller is used for any of the following purposes or an indication of any other purpose for which it is used:
    • (i) for controlling pressure or flow rate,
    • (ii) for controlling liquid levels,
    • (iii) for controlling temperature,
    • (iv) as a transducer,
    • (v) as a positioner, or
    • (vi) as an emergency response device; and
  • (c) its operational setting, including its supply pressure and, if any, its band setting, along with its design bleed rate for that operational setting.

Pneumatic Pumps

  • 28 (1) Unless an operator for an upstream oil and gas facility has a permit issued in accordance with subsection 30(2), a pneumatic pump used at the facility must not function using hydrocarbon gas if the pump has, in a month, pumped more than 20 L of liquid per day on average over the month.

Demonstration of quantity of liquid pumped

(2) An operator of the facility must, for each pump that operates in a month at the facility, demonstrate the quantity of liquids pumped per day on average over the month by means of

  • (a) a record of the quantity of liquid pumped during that month; or
  • (b) documents that establish that the pump could not have pumped more than 20 L of liquid per day on average over the month.

Non-application of subsection (2)

(3) Subsection (2) no longer applies in respect of the pump as of the end of a month for which the pump operates at the facility and there are records of the quantity of liquid it pumped, or other documents, establishing that the pump pumped, or could have pumped, more than 20 L of liquid per day on average over the month.

Non-application — conservation or destruction equipment

29 (1) Subsections 26(1) and (2) and 28(1) and (2) do not apply in respect of a pneumatic controller or pneumatic pump if hydrocarbon emissions from it are captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.

Tagging of not being subject

(2) A pneumatic controller or pneumatic pump that is referred to in subsection 26(3) or 28(3) must be tagged to indicate that it is not subject to subsections 26(1), (2) or 28(1) or an entry to that effect must be made in an electronic tracking system.

Tagging of design bleed rate

(3) A pneumatic controller that is referred to in paragraph 26(3)(a) must be tagged to indicate its design bleed rate for its operational setting or an entry to that effect must be made in an electronic tracking system.

Identifier

(4) The tag or the entry referred to in subsection (2) or (3) must also include an identifier for the pneumatic controller or the pneumatic pump.

Permit — pneumatic pumps

30 (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 function using hydrocarbon gas while its hydrocarbon emissions are not captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.

Issuance of the permit

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

  • (a) there are reasonable grounds to conclude that it is not feasible, technically or economically, for the applicant to have the pneumatic pump function at the facility without using hydrocarbon gas or to have the pneumatic pump function using hydrocarbon gas while its hydrocarbon emissions are captured and routed to an emissions control device, including grounds based on
    • (i) the capital, operating and maintenance costs of any modifications at the facility to achieve that objective, and
    • (ii) the avoided costs and any economic benefits arising from the incurring of those capital, operating and maintenance costs; and
  • (b) the applicant has a plan that
    • (i) involves taking steps to minimize the emission of hydrocarbon gas from the pneumatic pump, including steps such as adjusting the capacity of the pump or its operational settings so as to achieve the desired rate of injection of chemicals from the pump with the least possible emissions, along with a schedule to implement the plan, and
    • (ii) can reasonably be regarded as feasible for the purpose of permitting the facility to comply with subsection 28(1) by January 1, 2026.

Duration

  • (3) A permit takes effect on January 1, 2023 and expires on the earliest of
  • (a) the day on which the pneumatic pump ceases to function using hydrocarbon gas,
  • (b) the day on which the hydrocarbon emissions from the pneumatic pump begins to be captured and routed to an emissions control device, and
  • (c) December 31, 2025.

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.

Other Equipment

Pipes and hatches

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

Sampling systems and pressure relief devices

32 A sampling system or a pressure relief device 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.

Revocation of Permit or Approval

Subsection 22(2) or 30(2)

33 (1) The Minister must revoke an approval issued under subsection 22(2) or a permit issued under subsection 30(2) if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in their application for the permit or the approval.

Conditions for revocation

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

  • (a) written reasons for the proposed revocation; and
  • (b) an opportunity to be heard, by written representation, in respect of the proposed revocation.

Administration

Registration

Registration report

34 (1) An upstream oil and gas facility 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 60 days after the later of the day on which these Regulations are registered under section 5 of the Statutory Instruments Act and the day on which the facility begins operations.

Updated information

(3) If the information provided in the registration report changes, a notice to that effect that contains the updated information and the information referred to in item 4 of Schedule 3 must, not later than six months after the change, be provided to the Minister.

Record-making and Keeping of Documents

Records — deadline

35 (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.

Five-year period

(2) The record, along with supporting documents, and any document that is required to be kept under these Regulations, must be kept for five years.

Place kept

(3) 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 and, in the latter case, an operator for that facility must, as soon as feasible, provide the Minister with the civic address of that other place or, if the civic address is not available,

  • (a) the legal subdivision within which the other place is located, if that other place is located in Manitoba, Saskatchewan or Alberta; and
  • (b) the latitude and longitude of that other place, in any other case.

Change of place

(4) If the other place changes, the operator must, within 30 days after the change, provide the Minister with the information that is required by subsection (3) in respect of the new place.

Provision of records

(5) On the Minister’s request, the operator must, without delay, provide any of the records or documents kept to the Minister.

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

36 The schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) (see footnote 53) is amended by adding the following item 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) section 4

(b) section 6

(c) subsection 8(2)

(d) section 11

(e) subsection 13(1)

(f) subsection 19(1)

(g) subsection 21(1)

(h) subsection 24(1)

(i) subsections 26(1) and (2)

(j) subsection 28(1)

(k) section 31

(l) section 32

Coming into Force

January 1, 2020

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

January 1, 2023

(2) Sections 19, 20 and 26 to 29 of these Regulations and paragraphs 30(f), (i) and (j) of the schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999), as enacted by section 36 of these Regulations, come into force on January 1, 2023.

SCHEDULE 1

(Subsections 2(1) and 26(3))

Information for Non-Application of Requirements Respecting Pneumatic Controllers

1 The name and civic address of the operator.

2 The name, job title, civic and postal addresses, telephone number and email address of the operator’s authorized official.

3 The name, job title, civic and postal addresses, telephone number and email address of a contact person, if different from the authorized official.

4 The name of the facility and the federal and provincial identification numbers for the facility, if any, and its civic address or, if the civic address is not available,

(a) the legal subdivision within which the facility is located, if it is located in Manitoba, Saskatchewan or Alberta; and

(b) its latitude and longitude, in any other case.

5 The calendar year in respect of which the information is provided.

6 The sum of the rated power of the compressors that are used at the facility.

7 The month and calendar year during which the pneumatic controller was installed.

8 The identifier for the pneumatic controller, along with its make and model and the name of its manufacturer.

9 An indication as to whether the pneumatic controller is used at the facility for any of the following purposes or an indication of any other purpose for which it is used:

(a) for controlling pressure or flow rate;

(b) for controlling liquid levels;

(c) for controlling temperature;

(d) as a transducer;

(e) as a positioner; or

(f) as an emergency response device.

10 The operational setting of the pneumatic controller, including its supply pressure and, if any, its band setting, along with its design bleed rate for that operational setting.

SCHEDULE 2

(Subsection 30(2))

Information for Permit for Pneumatic Pumps

1 The name and civic address of the operator.

2 The name, job title, civic and postal addresses, telephone number and email address of the operator’s authorized official.

3 The name, job title, civic and postal addresses, telephone number and email address of a contact person, if different from the authorized official.

4 The name of the facility and the federal and provincial identification numbers for the facility, if any, and either its civic address or, if the civic address is not available,

(a) the legal subdivision within which the facility is located, if it is located in Manitoba, Saskatchewan or Alberta; and

(b) its latitude and longitude, in any other case.

5 The month and calendar year that the pneumatic pump was installed.

6 The identifier for the pneumatic pump, along with its make and model and the name of its manufacturer.

SCHEDULE 3

(Subsections 34(1) and (3))

Information for Registration

1 The name and civic address of the operator .

2 The name, job title, civic and postal addresses, telephone number and email address of the operator’s authorized official.

3 The name, job title, civic and postal addresses, telephone number and email address of a contact person, if different from the authorized official.

4 The name of the facility and the federal and provincial identification numbers for the facility, if any, and either its civic address or, if the civic address is not available,

(a) the legal subdivision within which the facility is located, if it is located in Manitoba, Saskatchewan or Alberta; and

(b) its latitude and longitude, in any other case.

5 An indication as to whether hydrocarbon gas conservation equipment is used at the facility.

6 An indication as to whether hydrocarbon gas destruction equipment is used at the facility.

7 If there is a centrifugal compressor or a reciprocating compressor at the facility, the following information:

(a) the serial number of the compressor, along with its make and model;

(b) for a centrifugal compressor, an indication as to whether the seals are dry or wet;

(c) for each vent to which the emissions from the seals of a centrifugal compressor are routed, the number of those seals; and

(d) for each vent to which the emissions from the rod packings of a reciprocating compressor are routed, the number of those rod packings.

8 An indication as to whether the facility produced and received a combined volume of more than 60 000 standard m3 of hydrocarbon gas over the first 12-month period referred to in subsection 15(1) of these Regulations and, if so, when the period ends.

9 An indication as to whether the facility consists of a single wellhead with gathering pipelines connected to it.

10 An indication as to whether the facility is in operation other than for periods of planned shutdown.

11 An indication as to whether a pneumatic controller is used at the facility and, if so, the sum of the rated power of the compressors that are used at the facility.

12 An indication as to whether a pneumatic pump is used at the facility and, if so, whether the pump has, in a month, pumped more than 20 L of liquid per day on average over the month.

13 An indication as to whether the facility has a pipe with an open end, hatch, sampling system or pressure relief device.

[21-1-o]

  • Footnote 1
    A petajoule is equal to one quadrillion (1015) joules.
  • Footnote 2
    Environment and Climate Change Canada (ECCC). Facts on Climate Change: http://www.climatechange.gc.ca/default.asp?lang=En&n=F2DB1FBE-1.
  • Footnote 3
    Canada has committed to reducing GHG emissions by 291 Mt in 2030. Canada’s Second Biennial Report on Climate Change (2016): https://www.ec.gc.ca/GES-GHG/default.asp?lang=En&n=02D095CB-1.
  • Footnote 4
    Canada’s INDC submission to the UNFCCC (2015): http://www4.unfccc.int/submissions/INDC/Published%20Documents/Canada/1/INDC%20-%20Canada%20-%20English.pdf.
  • Footnote 5
    United States–Canada Joint Statement on Climate, Energy, and Arctic Leadership: http://pm.gc.ca/eng/news/2016/03/10/uscanada-joint-statement-climate-energy-and-arctic-leadership.
  • Footnote 6
    Leaders’ Statement on a North American Climate, Clean Energy, and Environment Partnership: http://pm.gc.ca/eng/news/2016/06/29/leaders-statement-north-american-climate-clean-energy-and-environment-partnership.
  • Footnote 7
    Definition of hydrocarbons: https://www.eia.gov/energyexplained/index.cfm?page=hgls_home.
  • Footnote 8
    Definition of natural gas: http://www.nrcan.gc.ca/energy/natural-gas/5641.
  • Footnote 9
    High-pressure field gas refers to raw gas at high pressure that is extracted from the ground.
  • Footnote 10
    Solution gas is natural gas which is dissolved in the reservoir along with crude oil, condensates and water.
  • Footnote 11
    Data from Canada’s Second Biennial Report on Climate Change: https://www.ec.gc.ca/GES-GHG/default.asp?lang=En&n=02D095CB-1.
  • Footnote 12
    See also the “Regulatory cooperation” section below.
  • Footnote 13
    A petajoule is equal to one quadrillion (1015) joules.
  • Footnote 14
    The TBS Canadian Cost-Benefit Analysis Guide: Regulatory Proposals can be found at http://www.tbs-sct.gc.ca/rtrap-parfa/analys/analystb-eng.asp.
  • Footnote 15
    Volatile organic compounds referred to through the document are referencing non-methane volatile organic compounds.
  • Footnote 16
    Petrinex is a joint strategic organization supporting Canada’s petroleum industry and is currently represented by the Government [the Alberta Department of Energy (DOE), the Alberta Energy Regulator (AER) and the Saskatchewan Ministry of the Economy (ECON)], and industry [represented by the Canadian Association of Petroleum Producers (CAPP) and The Explorers and Producers Association of Canada (EPAC)].
  • Footnote 17
    National Energy Board: Canada’s Energy Future 2016. https://www.neb-one.gc.ca/nrg/ntgrtd/ftr/2016pt/index-eng.html.
  • Footnote 18
    The number of facilities is based on facility level data from the Alberta Energy Regulator, the Petrinex database and the Clearstone Engineering: Update of Fugitive Equipment Leak Emission Factors, 2014.
  • Footnote 19
    A battery is a system of tanks or surface equipment that receives natural gas or bitumen from one or more wells prior to delivery to market or other disposition.
  • Footnote 20
    U.S. EPA, Natural Gas STAR Program: Reducing Methane Emissions from Component Rod Packing Systems, 2006.
  • Footnote 21
    U.S. EPA, Natural Gas STAR Program: Wet Seal Degassing Recovery System for Centrifugal Compressors, 2014.
  • Footnote 22
    U.S. EPA, Natural Gas STAR Program: Installing Vapor Recover Units on Storage Tanks, 2009. Combustor costs are estimated through manufacturer consultation.
  • Footnote 23
    Costs are derived from EPA, Background Technical Support Document for Proposed Standards: Oil and Natural Gas NSPS.
  • Footnote 24
    This cost is the sum of inspection and reinspections costs: [(Inspection time)*(cost/hr of OGI inspection)]+[(reinspection time)*(probability of leak)*(cost/hr of reinspection)].
  • Footnote 25
    Ibid.
  • Footnote 26
    Based on internal estimates and Greenpath: Modelling inputs for leak and vent rates, 2016.
  • Footnote 27
    Larger facilities typically have more pneumatic devices. Some facilities have no gas-driven pneumatics because they have already implemented the mitigation standard.
  • Footnote 28
    U.S. EPA, Natural Gas STAR Program: Convert Gas Pneumatic Controls To Instrument Air, 2016.
  • Footnote 29
    Source for costs estimates obtained from distributor consultations.
  • Footnote 30
    This total includes newly installed compressors moved from decommissioned facilities whose rod packing was previously replaced as a result of these Regulations.
  • Footnote 31
    It is assumed that the quantity of natural gas consumed in Canada would remain unchanged.
  • Footnote 32
    In the “‘One-for-One’ Rule” section of the Regulatory Impact Analysis Statement (RIAS), these costs are also annualized at $1.1 million in 2012 dollars over a 10-year period (2018–2027) using a 7% discount rate as per the Red Tape Reduction Regulations.
  • Footnote 33
    Clearstone Engineering: Update of Fugitive Equipment Leak Emission Factors, 2014.
  • Footnote 34
    U.S. EPA: Protocol for Equipment Leak Emission Estimates, 1995, https://www3.epa.gov/ttnchie1/efdocs/equiplks.pdf. Clearstone Engineering: CH4 and VOC Emissions from the Canadian Upstream Oil and Gas Industry — Volume 2, July 1999.
  • Footnote 35
    U.S. EPA: Background Technical Support Document for Proposed Standards: Oil and Natural Gas NSPS, 2011.
  • Footnote 36
    The Prasino Group: Final Report for determining Bleed Rates for Pneumatic Devices in British Columbia, 2013.
  • Footnote 37
    EDF: Economic Analysis of Methane Emission Reduction Opportunities in the Canadian Oil and Natural Gas Industries, 2015.
  • Footnote 38
    U.S. EPA, Natural Gas STAR Program: Wet Seal Degassing Recovery System for Centrifugal Compressors, 2014.
  • Footnote 39
    Clearstone Engineering: Update of Fugitive Equipment Leak Emission Factors, 2014.
  • Footnote 40
    Average composition of gas ratios from provincial reported information were used for the facility production venting standard estimates.
  • Footnote 41
    Canada’s Second Biennial Report on Climate Change to United Nations Framework Convention on Climate Change can be found at https://www.ec.gc.ca/GES-GHG/02D095CB-BAB0-40D6-B7F0-828145249AF5/3001%20UNFCCC%202nd%20Biennial%20Report_e_v7_lowRes.pdf.
  • Footnote 42
    Note that SCC and SCCH4 estimates are rounded and converted to 2015 dollars for the analysis. Further information regarding the social cost of methane can be found in the Technical Update to Environment and Climate Change Canada’s Social Cost of Greenhouse Gas Estimates at http://www.ec.gc.ca/cc/default.asp?lang=En&n=BE705779-1.
  • Footnote 43
    As in the analysis of industry compliance costs, it is assumed that the quantity of natural gas consumed in Canada would remain unchanged.
  • Footnote 44
    Historic price differential between AECO-C and Henry Hub natural gas prices calculated using 2009–2015 price data.
  • Footnote 45
    National Energy Board “Canada’s Energy Future 2016: Energy Supply and Demand Projections to 2040 — Appendices”, 2016 https://apps.neb-one.gc.ca/ftrppndc/.
  • Footnote 46
    As per the Red Tape Reduction Regulations, these values are calculated using a 10-year time frame, discounted at 7% in 2012 dollars. The weighted average wage rate was assumed to be about $38 per hour in all cost calculations. The weighted average time per facility was estimated to be about 9 hours per facility.
  • Footnote 47
    Information taken from the Multi-Sector Air Pollutants Regulations (Engines). The Regulatory Impact Analysis Statement can be found at http://www.gazette.gc.ca/rp-pr/p2/2016/2016-06-29/html/sor-dors151-eng.php.
  • Footnote 48
    Ibid.
  • Footnote 49
    Canada-Nova Scotia Offshore Petroleum Board and the Canada–Newfoundland and Labrador Offshore Petroleum Board.
  • Footnote 50
    A petajoule is equal to one quadrillion (1015) joules.
  • Footnote 51
    The public statement regarding the strategic environmental assessment for the Clean Air Regulatory Agenda is available at the following address: www.ec.gc.ca/ee-ea/default.asp?lang=en&n=4F7D3B45-1.
  • Footnote 52
    The Department’s Compliance and Enforcement Policy is available at www.ec.gc.ca/alef-ewe/default.asp?lang=en&n=AF0C5063-1.
  • Footnote 53
    SOR/2012-134
  • Footnote *
    Discounted to 2016, using a 3% discount rate.
  • Footnote **
    Discounted to 2016, using a 3% discount rate.
  • Footnote a
    S.C. 2004, c. 15, s. 31
  • Footnote b
    S.C. 1999, c. 33
  • Footnote c
    S.C. 2009, c. 14, s.80
  • Footnote d
    S.C. 2008, c. 31, s. 5