Country
Assessment
Directive 056: Energy Development Applications and Schedules, first released in 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.
Directive 060, 2020, Section 2.9 (Economic Evaluation of Gas Conservation; see footnote 1) requires upstream firms to conduct an economic analysis following the decision-tree framework. 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. All new and existing flares and vents must be evaluated, except for small intermittent sources (less than 100 m³ a month) in midstream facilities such as processing plants, pipelines, and compressor stations (Sections 4, 5, and 6 of Directive 060).
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. Directive 060 instructs oil, gas, and power generation price forecasts to be used; and asks for details on reserves, capital, and operating cost assumptions. A conservation project is considered economic, and thus requires that the gas be conserved, if the net present value of the project is greater than Can$55,000 (about US$40,400 as of May 2023). In section 21 of this chapter, we discuss how fiscal incentives influence this economic assessment.
Companies must accurately measure and report volumes of associated gas at all oil facilities. Requirements for measuring and reporting volumes of gas flared, incinerated, and vented are provided in Directive 017 and Directive 007: Volumetric and Infrastructure Requirements, and the Oil and Gas Conservation Rules .
For the upstream sector, Section 2.13 of Directive 060 requires flared and vented solution gas to be reported monthly through Petrinex (Canada’s Petroleum Information Network) as per Directive 007. Section 5 of Directive 060 requires separate reporting of all monthly flared and vented volumes at gas processing plants. Flaring of sour gas must also be reported on the S-30 Monthly Gas Processing Plant Sulphur Balance Report.
According to Section 8 of Directive 017, 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. 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.
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; see footnote 1) 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 March 2023, it recorded 58 flaring violations. The AER handled almost all of them via notices of noncompliance or site inspections, but it also imposed administrative penalties in a few cases. Facilities may be shut 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 such as conversion efficiency, smoke emissions, ignition, and stack design 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$40,400 as of May 2023), 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 passed Bill 19, the Technology Innovation and Emissions Reduction Implementation Act, which laid the foundation of the market-based Technology Innovation and Emissions Reduction (TIER) system to induce industries to reduce emissions. Facilities that voluntarily reduce emissions may qualify for offsets or performance credits under the Alberta Emission Offset System.
In 2019, the original TIER Regulation 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.
In the past, the carbon price applied 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 between 10,000 and 100,000 tCO2e to voluntarily comply with the regulation, or opt in, and reduce the administrative burden for regulated conventional oil and gas facilities in exchange for an exemption from Canada’s federal carbon price (see section 22 in the preceding 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.
To align with the federal changes discussed in section 22 of the preceding case study, the TIER Regulation was updated at the end of 2022 . Carbon prices will match federal prices set for the 2023–30 period. The opt-in threshold is lowered from 10,000 to 2,000 tCO2e per year, enabling smaller firms to participate in the offset market. Amended regulations introduce two new credit classes: sequestration credits and capture recognition tonnes. Companies can convert the emissions offsets associated with a sequestration project to sequestration credits, which follow the same rules governing banking, trading, and compliance. Companies can convert sequestration credits to capture recognition tonnes, which must be used in the year of capture.
Amended regulations increased credit use limits (“true-up obligation”—the quantity by which a regulated facility’s total regulated emissions exceed its permissible emissions for the year) to 90 percent by 2026. Since offsets and credits can be used only once by their owner, the higher percentage is expected to encourage the earlier retirement of more offsets and credits and, thus, investment in new emission reduction activities.
Also, the TIER system now includes emissions from flaring. The flaring reduction target is set at 10 percent for 2023, with further reductions of 2 percent annually. Venting and fugitive emissions are not considered.
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.
The cumulative volume of flaring authorized for well workover or maintenance operations cannot exceed 50,000 cubic meters (m³) in a year. There are also various limits on flared volumes that trigger different reporting. British Columbia’s new methane regulations are designed to reduce methane emissions by 10.9 million tonnes of carbon dioxide equivalent (tCO2e) over a 10-year period starting in 2020.