Alberta is Canada’s largest oil and gas producer. The province accounts for about half of liquid fuel and more than 60 percent of gas production in Canada. Three-quarters of the output comes from the oil sands in northern Alberta. The oil and gas industry emits about half of Alberta’s GHG emissions. The AER Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting, 2020 (Directive 060, 2020 hereafter) incorporates recommendations to reduce flaring made by the Clean Air Strategic Alliance (n.d.) in 2002, 2004, and 2005.

With the Pan-Canadian Framework on Clean Growth and Climate Change in 2016, Canada committed to reducing methane emissions from the oil and gas sector by 40–45 percent from 2012 levels by 2025. Alberta committed to reducing methane emissions from the oil and gas industry by 45 percent from 2014 levels. In 2018, the ECCC published Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) SOR-2018-66. Provinces can choose to adopt these regulations or draft their own to meet or exceed the stated targets. Section 10 of the Canadian Environmental Protection Act, 1999, authorizes the minister of the environment to defer to “equivalent” regulations promulgated by a provincial government. In 2020, the government of Alberta and the federal government agreed that there were provisions in Alberta Regulation 244/2018, Methane Emission Reductions Regulation equivalent to the federal methane regulations.

To align its directives with the agreement, the Alberta Energy Regulator (AER) issued Bulletin 2020–12: Requirements Aimed at Reducing Methane Emissions Amended, 2020, and made changes to Directive 017: Measurement Requirements for Upstream Oil and Gas Operations, 2018 (Directive 017, 2018 hereafter) and Directive 060, 2020. Directive 060, 2020, applies to all operations approved under Section 10 of the Oil Sands Conservation Act, 2000, with the exception of oil sands mining operations, which do not need to flare or vent during bitumen mining.

The Ministry of Environment and Parks, known as the Alberta Environment and Parks (AEP), a governmental body, regulates air quality and is responsible for setting emissions and air quality standards under the Climate Change and Emissions Management Act, 2003. Flaring and venting are subject to gas emission limits and emission offsets to achieve reductions.

Directive 060, 2020, follows CASA recommendations; it defines limits on the total annual volume of gas flared, incinerated, and vented at all upstream wells and facilities. If flaring and venting of solution gas exceed the limit in any year, the AER will impose reduction limits for individual operating sites based on the analysis of the most recent annual data available.

Section 2.1 sets an annual solution gas flaring limit of 670 million m³. Acid gas volumes from gas sweetening (which are typically continuously flared) are excluded. Gas plants must not exceed six major nonroutine flaring events in any consecutive (rolling) six-month period.

Per Section 2.3, the combined flaring and venting volume is limited to no more than 900 m³ a day. Operators must follow the decision tree approach recommended by CASA and demonstrate the economics of conservation options (see the Economic Evaluation section, and the Fiscal and Emission Reduction Incentives section of this case study).

Section 8 sets an overall vented gas (routine and nonroutine) limit at a site of 15,000 m³ or 9,000 kilograms (kg) of methane a month. The limit on the volume of routinely vented gas at a site is 3,000 m³ or 1,800 kg of methane a month. Section 8.6 prescribes equipment-specific limits on venting.

Facilities that emit more than 100,000 tonnes of GHG a year are required to reduce their emissions intensity by 12 percent under the Climate Change and Emissions Management Amendment Act, 2003.

The Responsible Energy Development Act, 2012, created the AER from the existing Energy Resources Conservation Board. Several laws governing oil and gas activities in the province, including their conservation, lay the foundation for the AER’s regulation of flaring and venting along with the following other acts: 

• the Alberta Mines and Minerals Act, 2000 
• the Oil and Gas Conservation Act, 2000 
• the Gas Resources Preservation Act, 2000 and implementing regulations, Alberta Regulation 151/71: Oil and Gas Conservation Rules, 1971 
• Oil Sands Conservation Act, 2000.

AER Directive 060, 2020 provides comprehensive guidance on flaring and venting. The requirements set forth in the directive are aligned with the Alberta Ambient Air Quality Objectives. Alberta Regulation 244/18: Methane Emission Reductions is an implementing regulation issued under the Environmental Protection and Enhancement Act, 2000. It applies to all upstream oil and gas facilities except processing plants approved under Section 11 of the Oil Sands Conservation Act, 2000.

The Climate Change and Emissions Management Act, 2003 created the framework for regulators setting limits and pursuing various strategies to reduce emissions. Emissions limits are regulated under the Technology Innovation and Emissions Reduction Regulation, 2019, which superseded and replaced the Carbon Competitiveness Incentive Regulation, 2018, which replaced the Specified Gas Emitters Regulation, 2007. Companies have three ways to meet their reductions: make operating improvements, buy an Alberta-based credit (see the Use of Market-Based Principles section of this case study), or contribute to the Climate Change and Emissions Management Fund.

Alberta has jurisdiction over flaring, venting, and incineration, for which the province has comprehensive regulations. Emissions regulations are aligned with federal legislation and regulations. 

The ownership of oil and gas resources is split between the provincial government, the federal government, private freehold owners, and First Nations. Alberta owns about 80 percent of the mineral rights. The federal government owns 9 percent, including on most Indian reserves and national parks. The remainder is held privately under freehold ownership. The rights to explore for, develop, and produce oil and natural gas, including associated gas, are transferred to participants through licenses. 

The AER is the sole, independent regulator responsible for upstream oil, gas, and oil sands activities in the province, including flaring and venting. The AER’s governance structure is designed to provide both strong corporate oversight and independent adjudication. The AEP regulates the air quality and emissions generated during oil and gas activities.

At both the federal and provincial levels, the respective energy regulators have clearly defined responsibilities, with no overlapping or conflicting mandates. Agencies coordinate through collaboration. The AER’s statutory powers, mandates, and functions are governed by the Ministry of Energy, Ministry of Environment and Parks, and Ministry of Indigenous Relations. The AER is responsible for environmental assessments of energy projects; the AEP is responsible for environmental assessments of non–energy resource activities. Environmental approvals are required if any substance that could harm the environment is released. All oil and gas activities receive such approval from the AER.

The enforcement mechanism is outlined in the AER’s Manual 013: Compliance and Enforcement Program, 2020, which ensures a risk-informed approach that balances three compliance components: education, prevention, and enforcement. Numerous tools are available to the AER, including notices, warnings, orders, administrative sanctions, penalties, and prosecution. The AEP has similar compliance enforcement tools. It also regularly publishes orders related to noncompliance.

Section 3 of Directive 060, 2020 (“Temporary and Well Test Flaring and Incinerating”) does not require a permit for unplanned nonroutine flaring and incineration, such as during process upsets and emergencies. In addition, the AER does not require permits for flaring at oil and bitumen batteries. Under certain other conditions (for example, compliance with the percentage of hydrogen sulfide limits or with the Alberta Ambient Air Quality Objectives), permits are not required. These conditions are confirmed by the decision-tree tool adopted from CASA recommendations (Section 3 of AER Directive 060, 2020). 

According to Section 3 of Directive 060, 2020, planned nonroutine flaring and incineration events require a temporary flaring or incineration permit from the AER, with advanced filing of proper documentation. Section 3 lists the conditions that require a temporary flaring permit and describes the requirements for obtaining the permit. All permit applications are published on the Public Notice of Application webpage. The AER may issue a single “blanket” permit to cover several flaring events at different sites in an area if requested by the licensee. Companies may request a variance from the requirements if they have sufficient justification. Licensees must provide specific engineering, economic, and operational information to justify flaring or incinerating gas volumes above the volume allowance threshold. The AER does not consider venting an acceptable alternative to flaring or incineration (except for inert gases). It requires that gas be flared if gas volumes are sufficient to sustain stable combustion or conserved. 

Directive 056: Energy Development Applications and Schedules, 2021, presents the requirements and procedures for filing a license application to build or operate any petroleum industry on-site installations and the volume that is disposed of by burning in a flare or incinerator. Applicants proposing to flare, incinerate, or vent gas should comply with the requirements of Directive 060, 2020, and Section 8 of Alberta Regulation 151/71: Oil and Gas Conservation Rules, 1971.

Since 2018, management of fugitive emissions has been based on a systematic program of detecting and repairing leaks and malfunctioning equipment. The AER requires operators to develop and document a Methane Reduction Retrofit Compliance Plan containing a schedule to replace and retrofit existing equipment and allocating funding to reduce venting. The plan must set an overall limit on the volume of vented gas at all existing and future oil and gas sites by 2023. 

The framework for managing flaring and venting prescribed by Directive 060, 2020, Section 2 (Economic Evaluation of Gas Conservation) requires firms to conduct an economic analysis following the decision-tree framework. All new and existing flares and vents must be evaluated, except for small intermittent sources (less than 100 m³ a month). 

Alberta has more than 450,000 oil wells of mainly lower productivity and a small number of large oil sands projects. A facility’s individual energy needs will determine the optimal utilization strategy, how much associated gas it produces, and the well’s access to processing and pipeline infrastructure. The break-even economic criteria allow for the recovery of financing costs as well as capital and operating expenses. Conservation options include delivering gas to the market and using it on site as a fuel and for electricity generation and reservoir pressure maintenance. A conservation project is considered economic, and thus requires that the gas be conserved, if the net present value of the project before tax is greater than Can$50,000 (about US$39,500 as of September 2021). Every 12 months, licensees should update the conservation economics for any site that is flaring or venting a combined volume of more than 900 m³ a day. The licensee should keep this information on file and provide it to the AER upon request within five working days.
 

Companies must accurately measure and report volumes of associated gas at all oil facilities, in accordance with Directive 060, 2020. Section 5 requires separate reporting of all monthly flared and vented volumes at gas plants. Flaring of sour gas must also be reported on the S-30 Monthly Gas Processing Plant Sulphur Balance Report. According to Section 8, the operator must include the following information in its annual methane emissions report:

• the volume of fugitive emissions by facility
• the corresponding mass of methane emitted by facility 
• the type and date of survey
• the number of sources per site per facility.

The AER also requires a Fugitive Emissions Management Program following the survey and equipment guidance from the AER. The Fugitive Emissions Management Program should identify preventative maintenance practices; procedures for conducting surveys of fugitive methane emissions; screenings at a facility level (annually or three times a year depending on the type of facility or equipment); training programs; and procedures to track, manage, and verify the status of equipment repairs. Repairs to equipment with fugitive emissions must be made within 24 hours if the methane emissions cause an off-site odor, a pilot or ignitor on a flare stack has failed, or the emissions pose a safety risk. Otherwise, the equipment must be repaired within 30 days, unless a shutdown is required to complete the repair, the emissions have a hydrocarbon concentration of 10,000 parts per million or less, or the source is a surface casing vent flow. The AER will consider innovative and science-based alternatives to the Fugitive Emissions Management Program. Alternative programs may incorporate the use of various technologies, such as unmanned aerial vehicles, vehicle-mounted sensors, and continuous monitoring devices to detect, track, repair, and report fugitive emissions (Section 8 of AER Directive 060, 2020).
 

Most reporting is monthly. Section 2 of Directive 060, 2020 requires flared and vented solution gas to be reported monthly through Petrinex (Canada’s Petroleum Information Network). According to Section 8 of Directive 017, 2018, an annual methane emissions report must be submitted electronically to the AER by June 1 of the following calendar year. The first reporting period was 2019.

According to Directive 017, 2018, measurements of continuous or intermittent flare and vent sources must be undertaken at all oil and gas facilities where annual average volumes per facility exceed 500 m³ a day; otherwise flare volumes can be estimated. Single-point measurement uncertainty must be ±5.0 percent, and monthly volume uncertainty must not exceed ±20.0 percent.

According to Section 5 of Directive 060, 2020, when metering is not required and is not carried out, engineering estimates must be used to report any flared gas that is not measured. According to Section 8, methane emissions may be quantified using continuous metering, periodic testing, or estimates based on accepted engineering practices.

According to Manual 015: Estimating Methane Emissions, 2020, emissions may be estimated using emission factors, the equations included within the manual, or engineering estimates as described in the Guide for Reporting to the National Pollutant Release Inventory. Any updates in Directive 060, 2020 or Directive 017, 2018, supersedes the guidance in the manual.

According to Section 10 of Directive 060, 2020, operators should maintain a log of flaring, incineration, and venting events and respond to public complaints. Records should be kept for at least 12 months. Section 8 requires operators to retain records of methane emissions for four years from the date they were created unless otherwise noted and provide them to the AER upon request. Section 5 requires gas plant operators to provide documentation for metering or estimating flared and vented gas volumes upon request from the AER.

The AER regularly publishes comprehensive reports on industry activity at daily, weekly, monthly, annual, and any other relevant frequency. For example, the ST60: Crude Oil and Crude Bitumen Batteries Monthly Flaring, Venting, and Production Data show historical data on crude oil and bitumen production from crude oil and bitumen batteries and flaring and venting at the batteries by location, type, and operator; they also indicate where the conservation of gas has been economically feasible. The AER also publishes monthly enforcement reports (ST108) and year-end reports (ST60B: Upstream Petroleum Industry Flaring and Venting Report). Reports include flared and vented volumes reported to the AER. 

AER Manual 013: Compliance and Enforcement Program, 2020 states that flaring, incinerating, and venting audits are required to ensure that flare systems are designed and operated appropriately and in accordance with approved conditions. The manual outlines the various tools available to the AER, including fees and monetary penalties. A schedule of fees can be found in Alberta Regulation 151/71: Oil and Gas Conservation Rules, 1971.

According to 244/18: Alberta Methane Emission Reductions Regulation, 2018, an operator that violates venting limits, reporting requirements, or any other obligations imposed by the AER (mainly via Directive 060) faces a maximum fine of Can$50,000 (about US$39,500 as of September 2021) for an individual and Can$500,000 (about US$395,000 as of September 2021) for a corporation.

The Alberta Administrative Penalty Regulation, 2003, is an implementing regulation of the Environmental Protection and Enhancement Act, 2000. The maximum administrative penalty that environmental regulators may impose is Can$5,000 (about US$3,950 as of September 2021) for each contravention or each day or part of a day on which the contravention occurs and continues.

Alberta’s legislation includes rising levels of sanctions depending on the seriousness of the violation, including production shut-in or suspension of application processing. Section 25 of the Oil and Gas Conservation Act, 2000 authorizes the AER to cancel or suspend a license or approval for a definite or indefinite period. In particular, the AER may suspend well flaring permits for noncompliance. The AER’s decisions may be appealed under Section 36 of the Responsible Energy Development Act, 2012.

The AER Compliance Dashboard provides a compliance history of companies since 2014. The dashboard is searchable. Between 2015 and mid-2021, it recorded 51 flaring violations. The AER handled almost all of them via notices of noncompliance or site inspections. Facilities are shut in if operators do not take corrective actions to comply with AER instructions within the time provided.

Section 7 of Directive 060, 2020 details performance requirements for flaring and venting. They apply to flares and incinerators—including portable equipment used for temporary operations—in all upstream oil and gas industry systems for combusting sweet, sour, and acid gas during activities that include well completion, servicing, and testing. 

The AER has adopted CASA’s objective hierarchy and decision-tree framework for managing solution gas volumes and extended its application of the hierarchy to include flaring, incineration, and venting. The goal is to eliminate routine flaring, incineration, and venting. The objective hierarchy ranges from eliminating routine flaring, incineration, and venting of unburned gases to reducing the volume of such gas and improving the efficiency of the related systems.

In 1998, the government of Alberta announced the Otherwise Flared Solution Gas Royalty Waiver Program. Flaring gas that could be economically conserved makes the gas ineligible for a royalty waiver. The waiver is independent of the end-use of the gas and lasts for 10 years. Companies are also exempt from royalties if gas is used for on-site power generation. The gas royalty rate is 5 percent during the cost-recovery period, after which the royalty rate is a function of the reference gas price and production level.

According to Directive 060, 2020, gas conservation economics should account for royalties paid for incremental gas that would otherwise be flared or vented. If the economic evaluation results in a net present value of less than Can$55,000 (about US$43,400 as of September 2021), the operator should reevaluate the gas conservation project on a before-royalty basis. If the evaluation results in a net present value of Can$55,000 or more, the operator should proceed with the conservation project and apply to the AER for an “otherwise flared solution gas” royalty waiver.

Alberta put a price on carbon emissions for large industrial emitters in 2007. It put a carbon levy on fuel from 2017 until its repeal in 2019. In December 2019, Alberta’s Technology Innovation and Emissions Reduction Regulation, 2019 set a price of Can$30 (about US$24 as of September 2021) per tCO2e on emissions from the oil and gas, electricity, cement, agriculture, and other sectors. The benchmark price rises to Can$40 (about US$32 as of September 2021) per tCO2e in 2021 and Can$50 (about US$39 as of September 2021) per tCO2e in 2022. This regulation meets the federal criteria.

The carbon price used to apply to facilities that had emitted 100,000 tCO2e or more a year in 2016 or subsequent years. An amendment in July 2020 allowed facilities that emit less to voluntarily comply with the regulation and reduce the administrative burden for regulated conventional oil and gas facilities in exchange for an exemption from Canada’s federal carbon price (see the Use of Market-Based Principles section in the Canadian Federal case study). Also, firms are offering a lease-to-own program for nonemitting facility equipment. This program allows companies to voluntarily reduce emissions and generate carbon credits to pay down equipment leases.

The AER allows flaring when conducted in accordance with Directive 060, 2020. However, an applicant for drilling and the landowner or land occupant may sign a zero-flaring agreement and file it along with the well application (Section 3.10). Once filed, the agreement becomes a condition of the well license. Should the licensee, operator, or approval holder fail to adhere to this agreement, operations at the well may be suspended. This agreement, including the condition, expires when production begins.

AER regulations on flaring, venting, and emissions cover pipeline and storage facilities. Most oil and gas produced in Alberta is exported to other provinces or the United States via pipelines. Occasionally, an imbalance between demand and supply, bottlenecks in pipelines, or permitting delays can affect upstream operations. In 2018, for example, western Canadian oil supply outgrew the export pipeline capacity, resulting in record crude price differentials. Alberta’s government mandated a production curtailment effective January 2019, later extended to December 31, 2020. Such a curtailment would likely reduce emissions from associated gas flaring but only temporarily.