Country
Assessment
British Columbia’s Flaring and Venting Reduction Guideline does not allow routine venting except under “the most exceptional circumstances.” If gas volumes are sufficient to sustain stable combustion, the gas should be flared or conserved. If venting is the only feasible alternative, it should meet the following requirements, set out in chapter 7 of the guideline: All continuous and temporary venting and their sources must be evaluated using the vent evaluation decision tree. Permit holders must burn all nonconserved volumes of gas if volumes and flow rates are sufficient to support stable combustion. The quantity and duration of vented gas must be minimized. A permit holder must have an adequate program for managing fugitive emissions. According to Section 1.10 of the guideline, entitled “Approvals and Notifications for Non-Conserving Facilities,” nonroutine flaring (such as for maintenance and emergencies) does not require a specific approval but may be subject to limitations specified in the facility permit. Permit holders should notify residents and the BCER of nonroutine flaring at facilities.
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.
The Canada Energy Regulator (CER) was formed under the Canadian Energy Regulator Act, 2019, replacing the National Energy Board. It regulates the Northwest Territories, Nunavut and Sable Island, submarine areas not within a province in the internal waters of Canada, and the territorial sea or continental shelf of Canada, as defined in the Canada Oil and Gas Operations Act, 1999. The act provides a clear separation between the operational and adjudicative functions of the regulator. The Canada–Newfoundland and Labrador Offshore Petroleum Board is an independent agency that regulates petroleum-related offshore activities. The Newfoundland and Labrador Department of Natural Resources part of the provincial government, regulates onshore petroleum-related activities. The Canada–Nova Scotia Offshore Petroleum Board regulates oil and gas activities in the Canada–Nova Scotia offshore area. The Canada–Newfoundland and Labrador Offshore Petroleum Board and the Canada–Nova Scotia Offshore Petroleum Board jointly regulate oil production off the coast of the maritime provinces and set limits on the volumes of gas flared in offshore installations in their respective jurisdictions. Canada’s constitution grants exclusive authority to the provinces to regulate mineral development within their boundaries. The major producing provinces have independent oil and gas regulators. Federal and provincial (as well as territorial and indigenous) governments share authority over environmental matters. Each province has its own environmental laws.
The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) SOR/2018-66, last amended on January 1, 2023, contain standards for extraction, primary processing, long-distance transport, and storage. The regulations apply to facilities producing or receiving more than 60,000 m³ annually of hydrocarbon gas, which includes methane and certain volatile organic compounds. Upstream oil and gas facilities are required to take the following actions, among others: Limit vented volumes to 15,000 m³ a year. Implement leak detection and repair, starting in 2020. Regular inspections will be required three times a year, and detected leaks are to be repaired within 30 days unless the facility is required to be shut down, in which case an action plan must be prepared and implemented. Conserve or flare gas instead of venting, starting in 2020. In many instances, but especially in technical matters such as the measurement of gas volumes flared or vented, these federal regulations defer to provincial flaring and venting rules and emissions limits, which provincial regulators implement. Provincial emission limits must meet or exceed federal targets.
Resource owners in Canada (the federal or provincial government, private freehold owners, or First Nations) generate revenues primarily through royalties and taxes paid to them by developers from selling extracted oil and gas. Royalties can be up to 45 percent in federal onshore and offshore fields. No evidence regarding federal fiscal and emission reduction incentives could be found in the sources consulted. However, provinces have fiscal incentive programs, such as royalty waivers to induce gas capture, thereby reducing flaring and venting (see the case studies on Alberta, British Columbia, and Saskatchewan).
According to the Canada Oil and Gas Operations Act, 1999 , the CER may suspend or revoke an operating license or an authorization for failure to comply with, contravention of, or default in respect of a fee or charge payable per the regulations made under Section 4 or a requirement undertaken in a declaration referred to in Subsection 5.11.
No evidence regarding federal performance requirements could be found in the sources consulted. However, provincial regulators provide detailed guidance on the performance of oil and gas operations, including flaring and venting.
Section 5 of the Canada Oil and Gas Drilling and Production Regulations, 2009 (“Management System, Application for Authorization and Well Approvals”; see footnote 8), requires that the application for authorization be accompanied by information about any proposed flaring or venting of gas. This information should include the rationale, rate, quantity, and duration of the flaring or venting. Provincial regulators have more specific guidelines on applying for and obtaining flaring and venting authorizations.
In October 2016, the federal government published the Pan-Canadian Approach to Pricing Carbon Pollution, which established the federal benchmark for the 2018–22 period. In December 2016, Canada’s First Ministers adopted the Pan-Canadian Framework on Clean Growth and Climate Change , which required all provinces and territories to implement carbon pollution pricing systems by 2019. Under the federal legislation, the Greenhouse Gas Pollution Pricing Act, 2018, the federal government introduced a two-part carbon pricing scheme: a fuel charge and an output-based pricing system (OBPS). The fuel charge started with a carbon price of Can$10 (about US$7.9 as of September 2021) per tCO2e, increasing to Can$30 (about US$24 as of September 2021) in 2021 and Can$50 (about US$39 as of September 2021) by 2022. The federal benchmark is updated to have an initial carbon price of Can$65 (about US$47.8 as of May 2023) in 2023, and this price is to increase by Can$15 (about US$11) every year to reach Can$170 (about US$125) in 2030 . This price applies in all provinces that do not set their own prices. The OBPS must be designed to encourage facilities to reduce their emissions. Performance standards must be set such that, at a minimum, the marginal price signal is equivalent to the federal benchmark. Provinces can set their emissions intensity standards. Facilities able to reduce their emissions below these standards are eligible for performance credits. The OBPS “must only apply to sectors that are assessed by the jurisdiction as being at risk of carbon leakage and competitiveness impacts from carbon pollution pricing.” The federal carbon pricing regime does not cover all industries. Methane emissions from the oil and gas value chain, for example, are not comprehensively addressed. Some provinces adopted the federal carbon pricing benchmark or introduced their own carbon tax, while others combined provincial fuel charges with the federal OBPS or vice versa. In all cases, provincial measures must be equivalent to the federal benchmark. Quebec and Nova Scotia have cap-and-trade systems, where the caps must be set consistent with the minimum carbon price. In 2019, Canada began designing the GHG offset program to encourage the cost-effective reduction of domestic GHG emissions or GHG removal projects from activities not covered by carbon pricing. The government issues offset credits only to projects that produce real, quantified, verified, and unique reductions in GHG. This offset program could provide incentives for upstream oil and gas producers to invest in offset projects.
Market diversity and access are crucial considerations for the Canadian oil and gas industry. The Canadian natural gas market has been fully liberalized since gas prices were deregulated in 1985. Most oil and gas producers rely on pipelines and require provincial and federal policies that allow infrastructure to be built to deliver natural gas to new markets. A license from the appropriate provincial regulator must be obtained to construct and operate a pipeline. The CER, as the federal regulator, has jurisdiction if the pipeline crosses provincial or international boundaries. Federally regulated gas pipelines are generally considered to be contract carriers. The CER sets tariffs and the terms and conditions of access through regulation. The CER has the power to ensure that pipeline tolls are just and reasonable. Access to gas transmission is generally by agreement, but the CER has the power to direct a gas pipeline to provide any available capacity to a third party.