Country
Assessment
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.
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).
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.
Section 122 of the Oil and Gas Conservation Regulations, 2012 , provides that the minister may issue administrative penalties if an operator fails to comply with the regulations, including flaring and venting limits, and requirements outlined in Section 51. The operator may apply to the minister within 45 days of receipt of invoice. Failure to submit the required information can be subject to a penalty of Can$100 per day or up to Can$1,000 a month, depending on the violation. Submission of false declaration is penalized up to Can$250,000 per incident. Failure to comply with the minister’s orders is subject to a penalty of Can$5,000 per day, up to a maximum of Can$200,000. Section 13 of Directive PNG076: Enhanced Production Audit Program, 2016 , states that if a declaration is not submitted via Petrinex, the Petrinex error EPP001 will trigger a penalty in accordance with the Oil and Gas Conservation Regulations, 2012. The Oil and Gas Emissions Management Regulations, 2019 , set out the penalties for excess emissions. Section 10 states that the minister may impose a penalty on a company whose oil facilities produce, in any year, combined emissions that exceed the limit determined in the regulations calculated using the formula AP = EE ´ D, where AP is the administrative penalty to be paid; EE is the amount by which the combined emissions exceed the combined emissions limit, expressed in tCO2e and calculated for the year in accordance with Section 9; and D is the dollar amount per tonne of excess emissions set out in Table 3 of the regulations’ Appendix. The penalty per tCO2e increases every year until 2024, when the unit penalty is fixed in nominal terms at Can$50. If a correction results in a change in the combined emissions for a licensee on December 31 of the year for which the combined emissions are calculated, the licensee is required to pay, within the period specified by the minister, a penalty on any amount by which the combined emissions at the oil facilities exceed the limit on combined emissions, calculated in accordance with Section 9, plus interest, calculated, at a rate of 10 percent a year. This payment is in addition to any penalty already paid for that year.
The Oil and Gas Conservation Regulations, 2012 , stipulate that gas flared or vented at an oil well or facility should not exceed 900 cubic meters (m³) a day unless it is an emergency and a reasonable level of precaution has been taken to protect human health, public safety, property, and the environment. Sections 6 and 7 of Directive PNG036: Venting and Flaring Requirements, 2019 , states that gas venting from a well or facility, including gas plants, is not permitted unless there is an emergency, and venting is required to protect human health, public safety, property, or the environment, including prevention of a fire or explosion.
No evidence regarding development plans could be found in the sources consulted.
Directive PNG036: Venting and Flaring Requirements, 2019 , imposes several restrictions on flaring and venting: Section 6.1 (Associated Gas Venting Limit) states that oil wells and facilities that flare and vent a combined volume of associated gas greater than 900 m³ a day should flare all nonconserved gas, unless it needs to be vented to avoid emergencies. Section 6.2 (Associated Gas Flaring) states that oil and gas facilities may flare in excess of 900 m³ a day if they meet the Directive S-20: Saskatchewan Upstream Flaring and Incineration Requirements, 2019 . However, if flared volumes exceed 900 m³ a day, and the flare is within 500 meters of an occupied dwelling, a public facility, or an urban center, the gas should be conserved unless the operator obtains consent from the occupants or approval from the regulator. Section 7.1 (Gas Venting) bans venting at gas wells and facilities, including gas processing plants unless it is an emergency. Section 7.2 (Gas Flaring) bans flaring at gas wells and facilities but allows for flaring at gas processing plants as per the conditions of their licenses. In addition, according to Section 5, no venting or flaring from any source should cause off-lease odors or cause emissions in excess of the Saskatchewan Ambient Air Quality Standards. Also, operators should not vent any volume of gas that contains hydrogen sulfide in a concentration greater than 10 moles per kilomole of gas as measured at the source, or 0.01 mole per kilomole as measured at the lease edge.
The 2016 Pan-Canadian Framework on Clean Growth and Climate Change set a federal benchmark, requiring all provinces and territories to implement carbon pollution pricing systems by 2019. Saskatchewan has an output-based pricing system, which is mandatory for facilities emitting more than 25,000 tonnes of CO2e per year and voluntary for facilities emitting more than 10,000 tonnes of CO2e per year. The minimum threshold was removed for upstream oil and gas facilities in late 2020. To comply, companies can pay the Saskatchewan Technology Fund a carbon fee, which was Can$30 (about $22 in May 2023) in 2020.