Canadian oil and gas methane rules to kick off in 2020 – others likely to follow

In 2018, Canada finalised regulations to reduce methane emissions from upstream oil and natural gas facilities, including extraction, primary processing, long-distance transport, and storage. Provisions to track and repair “fugitive” methane leaks and to limit emissions from compressors and fracked gas well completions went into effect in January; facility-wide venting limits and pneumatic equipment standards enter into force three years from now.

Although many of Canada’s provinces had previously regulated methane from oil and gas production facilities, either directly or indirectly through safety and waste prevention measures, this rule marks the first time that the Canadian government has targeted methane emissions from the oil and gas sector.

While Canada’s rules do not address all methane releases, they nevertheless add to a growing body of examples of regulation on methane emissions, which the IEA is collating and making available as part of its Methane Tracker. IEA analysis has consistently shown that action to reduce methane emissions is one of the most cost-effective options to reduce global emissions and an essential complement to efforts to bring down emissions of carbon dioxide.

The methane rule plays a key role in Canada’s GHG emissions targets

Canada intends for the new rule, alongside provincial regulations, to fulfil the country’s commitment to reduce oil and gas methane emissions by 40% to 45% below 2012 levels by 2025. That pledge supports Canada’s Nationally Determined Contribution (NDC) under the Paris Agreement, which sets an economy wide GHG target that specifically included methane.  Other countries likewise included methane reductions from this sector in their NDCs, and it is likely that more will do so in the next NDC round this year.

In 2017, Canada’s Greenhouse Gas (GHG) Inventory reported that around 1.5 million tonnes (Mt) of methane were vented or leaked from the oil and natural gas industry. In its inventory, Canada assumes that one tonne of methane is equivalent to 25 tonnes of CO2 (the 100-year Global Warming Potential [GWP] reported by the Fourth Assessment Report of the Intergovernmental Panel on Climate Change [IPCC, 2007]). Methane is therefore reported to be equal to around 39 Mt CO2 equivalent emissions (CO2-eq) and around 5.4% of the country’s total greenhouse gas emissions of 716 Mt CO2-eq.

The IEA estimates global methane emissions from the oil and gas sector totalled nearly 80 Mt in 2017.

Understanding the magnitude of the problem

Canada’s national inventory is largely based on periodic emission studies, with interim-year estimates determined by interpolation, using production information and other provincially-reported data. The periodic studies utilise component inventories, detailed production accounting data, emission factors, and the frequency and duration of emitting activities. Peer-reviewed short-term measurement studies suggest this inventory may under-estimate methane emissions, either because the rules do not require reporting of all sources, or because emission factors and activity factors are unrepresentative and incomplete. The IEA Methane Tracker estimates that methane emissions from oil and gas operations in Canada are around 2.3 Mt (57.5 Mt CO2-eq  when using the same conversion factor as Canada’s GHG Inventory).

Canada’s new methane rule includes reporting requirements that should improve emissions estimates. These include inventories of emitting components at upstream facilities; reports on volumes of gas vented, destroyed, and delivered off-site; and results of leak detection and repair (LDAR) inspections and monitoring.

Moreover, several features of the rule work to enhance the reliability of reported measurements. A responsible party must certify each report as “true, accurate, and complete.” Regulators may assess penalties for documents containing false or misleading information. And operators are required to maintain records to establish that they have calibrated monitoring and leak detection devices.  These are critical design features for a robust information gathering regime.

Initially, a “bottom-up” approach to methane reduction…

Canada’s 2018 regulations take a bottom-up approach to emissions reductions. The rule is organised by component or activity, and features targeted interventions: routing emissions to vents, replacing or controlling individual high-emitting components, and inspecting equipment for methane leaks. This approach differs in key ways from Norway’s use of a carbon tax to curb methane emissions, and Mexico’s new law, which largely empowers operators to choose how to achieve facility-wide emissions reductions from a predetermined baseline. Each approach poses a trade-off between flexibility, compliance certainty, and environmental impact.

A bottom-up approach offers easy metrics for compliance tracking – did an operator replace a valve, or not? – and when implemented with robust recordkeeping and reporting provisions may also enhance understanding of the scope of the emissions problem. However, unlike facility emission limits, the bottom-up approach does not guarantee an environmental outcome. Carbon taxes and facility emissions limits also provide operators with enhanced flexibility, while the payment of carbon taxes generates revenue. However, these methods can complicate oversight if regulators do not have a robust way to verify reported emissions.

The Canadian requirements in effect as of January 2020 are particularly focused on individual activities and components. For instance, operators must reduce methane emissions during completion of each onshore fractured gas well. They must also limit emissions from gas compressors, based on the equipment’s size and installation date.

In addition, upstream facilities that produce or receive at least 60,000 standard m3 (around 45 metric tonnes) of natural gas each year must inspect particular components three times a year for leaks, using a portable monitoring or optical gas-imaging instrument. Operators must repair actionable leaks within 30 days or during the next planned shutdown. Offshore facilities must monitor leaks in real-time with a gas detection system.

Beginning in 2023, larger onshore facilities will need to limit methane releases from pneumatic controllers and pumps, and close hatches and pipe openings when not in use. In addition, for the first time, facilities will become subject to a facility-wide annual venting limit of 15,000 m3, or about 10 metric tonnes of methane (offshore facilities must meet a venting limit this year, and only emergency venting is excluded).1 This limit will begin to shift the regulatory regime away from a bottom-up strategy towards a more results-oriented approach. However, the limit excludes several key sources of methane emissions, including releases from compressors, well completions, liquids unloading, and blowdowns.

…with possibilities to introduce market-based approaches in the future

Canada had considered a market-based approach along the lines of the Norway model. However, the rule notes that “adequate quantification protocols for tracking emissions” do not exist to ensure the program’s effectiveness. If emissions estimates improve, Canada may be in a position to revisit this decision.

In 2018, Canada enacted the Greenhouse Gas Pollution Pricing Act, applying a carbon price to fuels of $10 per tonne of CO2-eq in 2019, increasing to $50 per tonne by 2022. This carbon price applies in all provinces that do not instate their own. While vented and leaked methane emissions are not currently covered, abatement of this pollution might become eligible to generate offsets.

In 2019, Canada began designing the carbon tax offset program. This program could be a near-term method for upstream oil and gas producers to participate in the carbon pricing regime, while generating valuable emissions data. British Columbia has a model to offer, having approved projects to reduce fugitive and vented methane emissions from upstream natural gas activities to count as offsets for the provincial government’s GHG emissions. In Alberta, firms are offering a lease-to-own program for non-emitting facility equipment, through which companies can voluntarily reduce emissions and generate carbon credits to pay down the equipment leases. Future policy could leverage and build on these types of innovative programs.

Interactions between national and provincial rules

Canada’s Constitution grants exclusive authority to the provinces to regulate mineral development within their boundaries. However, the federal and provincial (as well as territorial and Indigenous) governments share authority over environmental matters. The methane rule seeks to avoid regulatory overlap.

Canada and provincial governments jointly regulate oil production off the coast of the Maritime Provinces, under the Canada-Newfoundland and Labrador Atlantic Accord Implementation Act and the Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act. The new rule will apply to these facilities until such time as the offshore regulations are amended to include methane provisions.

The rule also exempts onshore British Columbia and Alberta facilities from hydraulically fractured gas well completion practices and reporting requirements, because those activities are already subject to the provincial rules. In addition, flares must meet the standards set by British Columbia, Alberta, and Saskatchewan if located in those provinces (or Manitoba, which follows Saskatchewan standards).

More broadly, Section 10 of the Canadian Environmental Protection Act authorises the Minister of the Environment to defer to “equivalent” regulations promulgated by a sub-national government. Under this authority, Canada has determined that the methane regime in British Columbia is equivalent to the national methane rule. The two governments then negotiated an equivalency agreement. Alberta and Saskatchewan are also seeking an equivalency determination.

Options for the future

Canada’s new rule is not comprehensive. Onshore facility venting limits and LDAR programs only apply to facilities producing or handling more than 60,000 m3 of natural gas annually; Canada projects the provisions cover about 96% of onshore gas production facilities but only about 20% of onshore oil production facilities. The rule’s facility-wide venting limit also excludes significant sources of facility emissions. Moreover, operators are not required to control associated gas at oil wells. Finally, the rule covers neither downstream facilities nor the plugging of abandoned wells.

The final rule potentially enables innovation in methane detection by establishing a process for approving new LDAR technologies. It will be interesting to monitor use of this process, and whether it leads to the uptake of new technologies.

The rule’s reporting requirements should be evaluated to determine their utility in improving methane emissions baseline estimates. Looking forward, Canada might reconsider a market-based approach to regulating methane as understanding of the real level of methane emissions improves.

Canada’s regulation in context

There are many aspects of Canada’s new regulation that can be instructive for other countries and jurisdictions considering actions on methane abatement. The alignment of its rules with provincial rules can be a useful example for other federal countries. Another interesting area is the possibility to approve new leak detection technologies, to stimulate innovation in surveillance and other monitoring technologies.

Canada’s decision not to apply a carbon tax to oil and gas methane emissions – given the absence of robust baseline measurements – is noteworthy. Canada’s rule requires data collection that could improve emissions estimates and, among other things, enable the government to revisit this decision in the future. But the exercise is inherently more challenging in a dynamic, competitive market with hundreds of private firms producing, processing, and delivering natural gas. Part of Norway’s success with robust reporting and regulation through carbon pricing may be due to the relatively small number of industry players.

Alternatively, a country might consider a more outcome-based model for tackling methane. For instance, as we saw above, an important aspect of Mexico’s law on methane emissions requires operators to meet facility-wide emission limits. This approach, which relies on operators providing baseline and annual facility emissions estimates, can also help to fill data gaps. And yet, it requires heavy engagement by the regulator and truly independent third party validators to confirm reported emissions.

Ultimately, Canada’s rules reflect the environment in which they were crafted. The bottom-up approach had been taken by Canadian provinces as well as regulators in the United States. The initial focus on retrofitting and replacing component replacements may also be particularly suited to countries with widespread existing oil and gas infrastructure. As Canada and other countries implement their rules, there will no doubt be further lessons learned about the effectiveness of these approaches and their applicability to different contexts.

  1. The rule states, “any volume of hydrocarbon gas that is vented from the offshore facility in order to avoid serious risk to human health or safety arising from an emergency situation is excluded from the determination of the volume vented for the purpose of subsection.” Reporting requirements include descriptions of these emergency situations.