Canada’s enhanced methane regulations: What investors need to know

Canada’s finalization of long‑awaited oil and gas methane regulations marks a pivotal moment for the country – but the real test will be implementation.

The regulations received broad support from investors, who recognize their critical role in reducing risk. Continued engagement from the financial community will be essential to ensure companies implement these rules through credible, effective compliance strategies.

The rules aim to cut oil and gas emissions 72% by 2030, putting the country on track for world-leading standards.

By staying engaged and tracking how companies embed methane performance into compliance strategies and capital planning, investors can better manage risk, protect long-term value, and identify industry leaders as global standards continue to tighten.

Why methane regulation matters for investors

Methane accounts for nearly 30% of global warming, and oil and gas operations offer one of the fastest, lowest-cost reduction opportunities. In fact, the International Energy Agency estimates that worldwide, the oil and gas industry can achieve a 75% reduction using technologies available today — two-thirds of it at no net cost.

In Canada, the stakes are particularly high: the country is a top five global producer of oil and natural gas, and the sector accounts for roughly half of national methane emissions according to official estimates.

While efforts have been made to create a more accurate federal inventory, multiple peer-reviewed studies indicate that companies’ methane emissions are significantly higher than reported, complicating risk assessment.

For investors, methane pollution represents:

• Wasted product and lost revenue – over $2.2 billion CAD in wasted gas since the federal target was announced.
• Regulatory and legal risk as global standards tighten.
• Reputational and market‑access risk as buyers increasingly demand verifiable low‑emissions supply.
• Economic and job opportunities – Analysis from EDF economists shows that regulations targeting a 75% reduction could create ~34,000 jobs from 2027–2040 across manufacturing, services, monitoring, and repair. Reducing methane waste also increases royalties and corporate tax revenue, particularly in high-emitting provinces like Alberta.

What the final regulations do

The finalized federal rules closely resemble the draft regulations released in 2023, with several critical features investors should understand. They apply to upstream oil and gas, gas processing, transmission, and LNG facilities (offshore, downstream, and municipal distribution are excluded).

Environment and Climate Change Canada (ECCC) estimates that the regulations are among the lowest-cost greenhouse gas abatement measures ($48/tCO₂e average) with recoverable gas value of ~$2B CAD, and a net economic benefit of $23.9B CAD.

Ambitious reductions by 2030

Compliance begins January 1, 2028, with new sources required to meet all requirements by that date. Existing sources must implement leak detection and repair by the beginning of 2028, with additional requirements phasing in by January 1, 2030 – giving companies time to plan capital allocation, while early movers can still gain a competitive advantage. The regulations are projected to deliver a 72% reduction in oil and gas methane emissions by 2030.

Near‑elimination of routine venting

By 2030, upstream oil and gas facilities will largely be prohibited from venting methane, with narrow exceptions for emergencies, safety, or maintenance and for low-producing crude oil facilities. The regulation effectively bans routine venting from pneumatic controllers and sharply restricts venting from storage tanks, dehydrators, and casinghead gas, while imposing stricter day one requirements on new facilities starting January 1, 2028.

Stronger leak detection and repair (LDAR)

The regulation takes a risk-based approach to comprehensive leak inspections, meaning higher-risk upstream oil and gas facilities must be inspected quarterly with either an infrared capable camera or an instrument capable of detecting hydrocarbons at a concentration of 500 parts per million by volume (PPMV).

Facilities with equipment prone to leaks or malfunction such as flares, compressors, and pneumatics, are subject to the quarterly inspection requirement. All other facilities must be inspected annually.

Operators must conduct monthly instrument-based screening for large leaks, provided an operator visits the site in that month. Lastly, operators must hire an independent auditor to conduct an annual inspection with the aim of identifying large leaks.

Destruction of gas

Flaring or combustion is prohibited unless the operator demonstrates that they are unable to use the gas to produce useful heat or energy. Hydrocarbon gas destruction equipment must include several features to ensure their efficient and proper function.

Two compliance pathways

The regulations give operators two clear ways to comply, designed to balance certainty with flexibility.

Under the prescriptive pathway, companies must follow a strong leak detection and repair regime and a general prohibition on venting and flaring subject to certain exceptions. This pathway offers clarity and predictability, making it easier to assess compliance risk and implementation timelines.

The performance‑based pathway allows companies to comply by meeting strict, facility-level methane intensity limits. This pathway requires the deployment of robust monitoring, control, and data systems capable of demonstrating emissions outcomes and includes corrective action requirements when emissions exceed those limits. This option rewards early movers and operators that invest in continuous monitoring and system‑wide controls, while still holding them accountable to measurable results. Flexibility can deliver equivalent emissions reductions, but only if measurement-based monitoring, reporting, and verification are credible. Approved methods capable of demonstrating compliance with intensity thresholds – whether at the level of individual facilities or, where allowed, appropriate groupings of facilities – along with independent verification, and defined repair timelines reduce the risk that flexibility leads to higher emissions or noncompliance. To ensure equivalent protections, performance-based approaches must include safeguards that prevent intensity limits from enabling persistently high absolute emissions.

The regulations establish emissions intensity thresholds, periodic reporting, and documentation requirements that create standardized, auditable records of methane performance. While reports are submitted to the federal government and not automatically made public, investors and other stakeholders may request certain information under Canada’s Access to Information Act, though disclosures may be incomplete or delayed.

The Alberta question: equivalency, not exemption

The biggest uncertainty lies in provincial equivalency agreements, especially following the November 2025 Memorandum of Understanding (MOU) between Ottawa and Alberta.

The MOU suggested a later compliance date for Alberta (2035), raising concerns about delayed action and weakened ambition. Importantly, however, the Minister for Environment, Climate Change, and Nature, Julie Dabrusin, recently explained that the MOU doesn’t represent a delay because all provinces will need to achieve a 72% reduction by 2030, making this outcome compatible with Alberta achieving 75% by 2035.

Equivalency agreements allow provinces to implement their own rules, but only if they are demonstrably equivalent to the reductions that are likely to be achieved by the federal regulations.

It will be essential[AP1]  that all federal-provincial equivalency agreements be based on robust federal data compiled, in part, using direct emission measurement technologies. For example, while Alberta data shows its conventional upstream sector has reduced emissions by 51%, aerial data suggest the sector’s emissions are twice as high as reported. Whereas ECCC data – which incorporate these aerial measurements – shows that Alberta’s entire oil and gas industry has reduced emissions by 37%, suggesting the province has much further to go to meet the 75% reduction target.

For investors, the takeaway is straightforward:

• Provinces cannot simply opt out of methane reductions.
• Provincial pathways must still deliver emissions cuts consistent with federal objectives.
• Transparency and accountability in equivalency agreements matter for investor confidence.

British Columbia provides clear proof that strong rules can coexist with production growth: it has already cut oil and gas methane emissions 51% from 2014 levels while increasing natural gas production by more than 67%. Moreover, BC has already developed and implemented its own regulations aimed at meeting the 2030 federal target.

Global markets are moving, with or without Canada

Even as domestic negotiations continue, international expectations are accelerating:

• The EU Methane Regulation is already in effect and here to stay, requiring robust reporting and verification of gas imports by 2030.
• Japan and other Asian LNG buyers are strengthening supply-chain methane transparency and emissions expectations.
• The CEO-led Oil and Gas Climate Initiative (OGCI), representing over 40% of global production, has recommitted to near‑zero methane by 2030.
• IMEO’s Eye on Methane 2025 shows that more companies are joining the Oil and Gas Methane Partnership (OGMP) 2.0 and steadily improving measurement quality.

Early alignment with federal and global MRV standards and emissions reduction initiatives helps Canadian producers secure premium contracts, access financing, and reduce investor risk.

What investors should watch next

With the rules finalized, the next phase is implementation. Investors play a critical role in ensuring methane reductions materialize on the ground by asking companies about compliance strategies, capital allocation, and measurement credibility. Consistent investor expectations will reinforce regulatory intent, reduce implementation risk, and accelerate the adoption of best-in-class methane management across the sector.

Investors should focus on:

• Provincial equivalency agreement negotiations – Will provincial rules match federal ambition or leave gaps, particularly in Alberta? Critically, investors should ensure that the federal–Alberta MOU is not used as justification to weaken or delay implementation of the federal regulations. While the MOU references a 75% reduction target by 2035, this must not override the federal regulation’s requirement to achieve a 72% reduction by 2030, nor should it limit the potential to strengthen ambition toward a near-zero methane goal. How are companies preparing?
• Transparency and enforcement – Are equivalency agreements backed by public data and clear enforcement? Investors should also push for the use of strong, consistent emissions data across Canada—grounded in federal inventory methodologies and transparent reporting—rather than weaker or less transparent provincial datasets that could understate emissions and undermine comparability across jurisdictions.
• Company implementation – Are companies investing early in methane controls and monitoring? Are performance-based pathways supported by credible measurement and independent verification? Investors should ask for detailed emissions data and progress against intensity thresholds to ensure compliance and risk mitigation.
• Capital allocation– Are companies funding methane controls and monitoring? These decisions affect both risk and returns.
• Global MRV alignment – Are MRV practices keeping pace with international standards and global buyer demands? This is increasingly tied to market access and financing.

Canada’s final methane regulations set a clear direction of travel. How companies respond to raised expectations will distinguish leaders from laggards for the future of the global methane market.

 [AP1]This para still in progress