In 2016, British Columbia introduced regulations to eliminate routine flaring at oil and gas production facilities, following the province’s 2007 energy plan. British Columbia’s production of liquid fuels (including oil, condensate, and pentanes plus) accounts for less than 2 percent of Canadian liquids production. Gas production in British Columbia accounts for nearly 30 percent of total gas production in Canada. Oil production declined to roughly one-fourth its level in the early 2000s, but production of condensate increased, along with natural gas production from the unconventional Montney play in the province’s northeast. Gas production increased by a factor of 2.3 over 20 years; flaring volume decreased by approximately one fifth. 

As part of the 2016 Pan-Canadian Framework on Clean Growth and Climate Change, the government of Canada committed to reducing methane emissions from the oil and gas sector by 40–45 percent by 2025 from 2012 levels. In 2018, British Columbia committed to reducing fugitive and vented methane emissions by 45 percent by 2025 from 2014 levels (Clean BC Plan) and, in 2021, announced a roadmap that includes 75 percent reduction of methane emissions from the oil and gas sector by 2030 and near elimination of all industrial methane emissions by 2035. 

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 adopt these regulations or draft their own to meet or exceed the stated targets. In May 2018, the British Columbia Energy Regulator (BCER)—formerly known as the British Columbia Oil and Gas Commission (BCOGC) until early 2023—released the Flaring and Venting Reduction Guideline, 2018, last updated in September 2022. 

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 April 2020, an equivalency agreement between federal and British Columbia regulations was published. Accordingly, the federal government exempted British Columbia from federal regulation via SOR/2020-60, entitled “An Order Declaring that the Provisions of the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) Do Not Apply in British Columbia.” 

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.

Together with the Ministry of Energy, Mines and Petroleum Resources and the Climate Action Secretariat of the Ministry of Environment and Climate Change Strategy, the BCER has developed the Flaring and Venting Reduction Guideline, 2018 . This guideline covers flaring, incinerating, and venting at well sites, facilities, and pipelines, and includes guidance on flare approval requests; dispersion modeling; and the measuring and reporting of flared, incinerated, and vented gas. The guideline contains methane emission regulations to address the following primary sources of methane from the upstream oil and gas industry: pneumatic devices, equipment leaks, compressor seals, glycol dehydrators, storage tanks, and surface casing vents. The guideline aims to meet methane emission reduction targets and ensure that they are equivalent to federal regulations and targets. British Columbia’s carbon tax is applied to these emissions.

The following provincial laws govern the exploration for and production of oil and natural gas in British Columbia:

• the Oil and Gas Activities Act, 2008
• the Petroleum and Natural Gas Act, 1996
• the Environmental Management Act, 2003
• the Climate Change Accountability Act, 2007 (formerly GGRTA)
• the Clean Energy Act, 2010.

For large oil and gas operations, the BCER issues site-specific air discharge permits under the Environmental Protection and Management Regulation, 2010. Each permit contains requirements for limiting the release of air contaminants such as hydrogen sulfide, sulfur dioxide, oxides of nitrogen, hydrocarbons, carbon monoxide, and particulate matter. Requirements limiting air contaminants for smaller operations are specified in the Oil and Gas Waste Management Regulation, 2005, and the Drilling and Production Regulation, 2010. Other relevant secondary legislation includes the Administrative Penalties Regulation, and the Carbon Neutral Government Regulation, 2008.

British Columbia 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. The rights to explore for, develop, and produce oil and natural gas, including associated gas, are transferred to operators through licenses or leases.

The BCER is the sole provincial regulatory agency responsible for overseeing oil, gas, and geothermal operations as defined by the Oil and Gas Activities Act, 2008 . It is governed by a board of directors that sets the strategic direction and establishes accountability and transparency, including corporate risks, as part of the strategic planning process. The board has the power to create regulations concerning oil and gas activities. The BCER, in consultation with stakeholders, monitors progress to reduce the volume of solution gas that is flared or vented. When BCOGC was renamed BCER in early 2023, new board positions were added for a total of five to seven directors (previously, there were three directors). The board must now include indigenous representation.

The BCER and the CER (the federal regulator) have clearly defined responsibilities, with no overlapping or conflicting mandates. The BCER regulates flaring and venting activities in the province. The Environmental Assessment Office, a regulatory agency within the provincial government, manages environmental assessments.

The BCER has the authority to inspect, audit, and enforce compliance with laws and regulations, and sanction noncompliance under several laws (see sections 18 and 19 of this case study). It publishes the results of inspections, tickets and fines, warning letters, enforcement orders, and contravention decisions on the Compliance and Enforcement website.

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.

Chapter 2 of the Flaring and Venting Reduction Guideline  on temporary flaring approval for well testing, states that flaring for purposes other than those previously specified in Chapter 1, including well testing, must be approved in the facility permit. Approval to flare may be requested in the well permit application or by amending the well permit.

The Drilling and Production Regulation, 2010 , authorizes flaring at wells if the flaring is in line with the well’s permit or is related to drilling operations and is necessary because of an emergency. Flaring is also authorized for well workover or maintenance operations and when the cumulative quantity of flared gas does not exceed 50,000 m³ a year. Section 43 of the Drilling and Production Regulation, 2010, on flaring notification and reporting, requires a permit holder to notify the BCER at least 24 hours before a planned flaring event if the quantity of gas to be flared exceeds 10,000 m³. If an unplanned flaring event occurs and the amount of flared gas exceeds 10,000 m³, the permit holder should notify the BCER within 24 hours.

No evidence regarding development plans could be found in the sources consulted.

Section 1.8 of the Flaring and Venting Reduction Guideline  on economic evaluation of gas conservation, is similar to Section 2 of Alberta’s Directive 060 (see section 12 of the case study on Alberta). British Columbia’s guidance considers a solution gas conservation project with a net present value of less than Can$50,000 (about US$36,760 as of May 2023) uneconomic. The project economics should be reevaluated annually (within 12 months of the last evaluation) using updated prices, costs, and forecasts.

Chapter 10 of the Flaring and Venting Reduction Guideline  states the requirements for measuring and reporting volumes of gas flared, incinerated, or vented. These requirements are in addition to the requirements specified in the Measurement Guideline for Upstream Oil and Gas Operations, 2020; Oil and Gas Activity Operations Manual, 2020; the Oil and Gas Royalty Handbook, 2014; and the Drilling and Production Regulation, 2010 . Permit holders of oil and natural gas production and processing facilities must report volumes of gas greater than or equal to 100 m³ a month that are flared, incinerated, or vented in Petrinex. For royalty calculation purposes, these volumes are also reported through the BC-S2 or BC-19 forms of the Ministry of Finance. All flaring, incinerating, and venting from routine operations; emergency conditions; and depressurizing pipelines, compressors, and processing systems must be disclosed. Gas used for a pilot, a purge, or a blanket must be reported as either flared or vented.

The Greenhouse Gas Emissions Reporting Regulation, 2015, details the conditions and criteria for the mandatory reporting of GHG emissions by operators. Operators that emit more than 10,000 tCO2e a year must collect and report data on their emissions to the BCER. Submissions must be based on a process-flow diagram and include emissions from flaring, venting, and other fugitive emissions. The regulation also establishes verification bodies to evaluate reports from operators.

Chapter 10 of the Flaring and Venting Reduction Guideline  requires permit holders to demonstrate that gas volumes are determined accurately and reliably. They must have written documentation detailing the methodology used to determine flared, incinerated, and vented gas volumes for all their wells, pipelines, and facilities that must be available for review by an official.

Meters designed for expected flow conditions and range must be used to measure continuous or nonroutine flare and vent sources at all oil and gas production and processing facilities at which the total volumes of gas flared, incinerated, and vented per facility exceeds 500 m³ a day (excluding dilution gas) on an annual average basis. Chapter 2 of the Measurement Guideline for Upstream Oil and Gas Operations, 2020 , provides details regarding calibration and proving the accuracy of measurement devices.

Section 10 of the Flaring and Venting Reduction Guideline states that the BCER will accept flared, incinerated, and vented gas estimates if measurement is not stated as a requirement. The operator’s estimates should account for all gas flared, incinerated, and vented at its facilities (expressed to the nearest 100 m³ a month) during routine, emergency, and maintenance operations, including emissions while depressurizing vessels, compressors, and pipelines. Volume estimates should be based on engineering calculations. The BCER recognizes the Canada Association of Petroleum Producers’ Guide for Estimation of Flaring and Venting Volumes from Upstream Oil and Gas Facilities, 2002, as containing acceptable practices for estimating.

Section 10 of the Flaring and Venting Reduction Guideline  requires permit holders to produce documentation describing estimation of the volume of flared and vented gas and reporting procedures as well as operating logs if requested by the BCER. The documentation provided should include assumptions, mathematical formulas, estimation methodologies, and details on the means used to obtain and update input data. Permit holders should maintain a log for a minimum of 12 months of flaring and venting events and respond to any public complaints.

The BCER publishes monthly and annual flaring data on its website. Additional reports can be downloaded from the BCER website, which also has a range of other publications, tools, and data sets designed to inform and educate the general public, First Nations, communities, and government officials.

The Administrative Penalties Regulation, 2011 , establishes that a person who contravenes various responsibilities related to flaring and venting (Sections 42–44 of the Drilling and Production Regulation, 2010; see footnote 19) is subject to fines ranging from Can$20,000 (about US$16,000 as of September 2021) to Can$250,000 (about US$200,000 as of September 2021).

The BCER also uses the following tools to sanction operators that do not comply with laws and regulations:

• Orders are issued if there is a failure to comply with the Oil and Gas Activities Act, 2008 , associated regulations, permits or authorizations, or a previous order.
• Tickets are issued under the authority of provincial acts for which the BCER has regulatory responsibility, including the Water Sustainability Act, 2014, the Land Act, 1996, and the Forest Act, 1996.
• Charges are recommended to the Crown Counsel for prosecution and possible court action.

Section 44 of the Drilling and Production Regulation, 2010 , sets performance standards for the flare stacks operated by permit holders of a well or a facility. It also specifies the measures to be considered if the hydrogen sulfide content of the gas to be flared exceeds 1 mole percent. Flare and incinerator systems installed after the date the regulation came into force must be designed and operated within limits specified by a professional licensed or registered engineer. Flaring should not result in the emission of black smoke. Section 2.6, “Site-Specific Requirements Related to Well Flaring,” and Chapter 6, “Performance Requirements,” of the Flaring and Venting Reduction Guideline  provide additional information, including engineering standards by the American Petroleum Institute and other professional organizations that can be used as references.

British Columbia has fiscal incentives in place to induce the lease use or marketing of associated gas. There are two broad classifications for calculating natural gas royalties: conservation gas and nonconservation gas. Conservation gas is natural gas that has been produced as part of oil production that is conserved and marketed instead of flared. All other gas is considered nonconservation gas. Section 5 of the Oil and Gas Royalty Handbook, 2014 , shows how royalties are calculated under various gas prices and well classifications. Royalties paid for conservation gas are often as low as 8 percent, compared with up to 27 percent for nonconservation gas. This difference in royalty rates creates an incentive for producers to capture and market associated gas. In addition, according to Section 5.9 of the handbook, natural gas or by-products used for production, drilling, or re-injection are exempt from royalties and production taxes. Gas lost is also exempt from royalty and tax if the regulator deems that the loss is not the fault of the producer and the producer does not receive any compensation for the loss (for example, insurance proceeds). The lost gas includes flared and vented volumes.

British Columbia implemented the Carbon Tax Regulation, 2008, which was last amended in November 2022. The tax applies to the purchase and use of fossil fuels burned for transport, home heating, and electricity. It covers approximately 70 percent of provincial GHG emissions. The impact of the tax on consumers is compensated for by a reduction in personal and corporate income taxes by an approximately equal amount. The carbon tax increased gradually from Can$10 (about US$7.9 as of September 2021) per tCO2e in 2008 to Can$30 (about US$24 as of September 2021) per tCO2e in 2012, at which point the government froze the rate at Can$30 per tCO2e until other jurisdictions implemented similar carbon taxes. In 2018, the carbon tax was increased to Can$35 (about US$28) per tCO2e; in April 2019, it rose to Can$40 (about US$32 as of September 2021) per tCO2e, which for natural gas corresponds to Can$0.076 per m³. The updated regulation sets Can$50 per tCO2e for 2022 and beyond. The carbon taxes by fuel type are updated through 2026.

The Ministry of Environment and Climate Change Strategy has been managing a carbon offset program since 2010. In the oil and gas sector, offset projects have reduced flaring or venting, typically by using gas for electricity generation.

No evidence regarding negotiated agreements between the public and the private sector could be found in the sources consulted.

Most gas production in British Columbia is exported to other provinces or the United States via pipelines. Gas production increasingly comes from remote unconventional resource basins, such as the Montney and Horn River in the northeast corner of the province, which are far from consuming regions. The coordination of drilling activity with the development of sufficient midstream capacity can avoid bottlenecks in transport capacity and hence reduce flaring. The regulator encourages producers and third parties to pursue such coordination of midstream capacity and new production.