Technical Backgrounder: Federal methane regulations for the upstream oil and gas sector


As part of the Pan-Canadian Framework on Clean Growth and Climate Change, the Government of Canada reaffirmed its commitment to reduce methane emissions from the oil and gas sector by 40 to 45 percent from 2012 levels by 2025. Methane is a potent greenhouse gas (GHG) that is 25 times more powerful than carbon dioxide and methane emissions make up about 15 percent of Canada’s total GHG emissions. The oil and gas sector is the largest contributor to methane emissions in Canada.

In April 2018, Environment and Climate Change Canada (ECCC) published federal methane regulations to deliver on this commitment. ECCC has consulted extensively with provinces, territories, industry, environmental organizations and Indigenous peoples to develop robust and cost-effective regulations.

Regulatory design

These outcome-focused regulations apply to upstream oil and gas facilities, which are responsible for extraction, production, processing and transportation of crude oil and natural gas. The requirements target two key methane sources: fugitive emissions, which are unintentional leaks from equipment leaks, and venting emissions, which are intentional releases of methane into the air. The regulations contain both general and conditional requirements, as indicated below.

General requirements apply to all covered upstream oil and gas facilities:

  1. Compressors: As of January 1, 2020, covered compressors will be required to take action to conserve or destroy methane, or else to meet applicable vent limits. If a company opts not to conserve or destroy methane, it must demonstrate compliance with the limits via an annual measurement or continuous monitoring. Corrective action is required if those emissions exceed the limit applicable to the compressor, which depends on the installation date, the type of compressor, and its rated brake power.
  2. Well completions involving hydraulic fracturing: As of January 1, 2020, these sites must conserve or destroy gas in most circumstances instead of venting it into the air.

Conditional requirements apply to covered upstream oil and gas facilities handling significant volumes (at least 60,000 cubic metres/year of gas):

  1. Fugitive equipment leaks: As of January 1, 2020, upstream oil and gas facilities are required to start implementation of leak detection and repair program consisting of three comprehensive inspections per year at most upstream oil and gas facilities. Corrective action is required if leaks are discovered.
  2. Facility production venting: As of January 1, 2023, upstream oil and gas facilities must limit annual facility vented volumes of methane to 15,000 m3. These facilities would need to capture the gas and either use it onsite, re-inject it underground, send it to a sales pipeline, or route it to a destruction device. This requirement does not apply to vented gas from:
    1. specific temporary activities such as emergencies, liquids unloading, or equipment start-ups, shutdowns, and blowdowns;
    2. facilities that have vented less than 40,000 m3 in the past year without destroying or selling or re-injecting any gas; and
    3. processing equipment such as glycol dehydrators, compressors and pneumatic devices.
  3. Pneumatic devices:
    1. Controllers: As of January 1, 2023, facilities using natural-gas-powered pneumatic controllers must ensure that on-going emissions remain below 0.17m³ per hour.
    2. Pumps: As of January 1, 2023, pneumatic pumps are prohibited from emitting methane where the volume of liquid being pumped exceeds 20 litres per day.

Regulatory flexibilities

The first federal requirements come into force in 2020, with the rest of the requirements coming into force in 2023. The regulations were designed to ensure efficient results and limit impacts on smaller facilities by focusing on those facilities producing the majority of emissions.  Flexibilities have been extended in the final federal regulatory approach to include:

  • Facilities can implement an alternative leak detection and repair program, as long as it is demonstrated to similarly limit fugitive emissions compared to the regulatory program.
  • Facilities have flexibility in timing inspections to avoid the winter season.
  • If leak repairs are not possible without shutting down the equipment, the operator is allowed to wait more than 30 days to repair the leak, as long as the volume leaked in that period is not larger than would be released by shutting down the equipment.
  • Under exceptional circumstances, an extension for up to six months may be granted for repair.
  • The leak detection and repair provisions exclude sites with very limited potential leak points, such as single wellhead production sites and isolation valve sites on transmission pipelines. This makes the requirements more cost-effective.
  • Facilities have numerous ways to comply with the venting limit. They can capture the gas and reuse it, return it underground, sell it, or they can destroy the captured gas.
  • Small and low-use compressors are exempt from the compressor requirements.
  • The regulations include a range of emission limits to reflect different compressor sizes, types, and installation dates.
  • Well completion requirements do not apply in British Columbia and Alberta since existing provincial measures cover these activities. Well completion requirements also do not apply if the gas does not have sufficient heating value to support combustion.
  • Until December 31, 2025, a company can request a permit for pneumatic pumps if it is not feasible to comply with the requirements before the deadline.
  • In recognition of unique configurations of offshore operations, compliance can be linked to current regulatory mechanisms.

Regulatory impact analysis

The Regulatory Impact Analysis Statement (RIAS) assesses the impacts of the regulations in accordance with Treasury Board Secretariat’s Canadian Cost-Benefit Analysis Guide. Impacts are determined by comparing a baseline scenario, which estimates impacts in the absence of the regulations, with a regulatory scenario. All benefits and costs are incremental to the baseline scenario, unless otherwise specified.

The baseline emission projections for the oil and gas sector are determined using the production forecast of oil and gas from the National Energy Board, in combination with the National Inventory Report on Canada’s greenhouse gas emissions. These projections are developed in the Energy, Emissions and Economy model, one of the Department’s models for developing greenhouse gas emission projections and analysing policy impacts in Canada. This analysis uses emissions projections as reported in Canada’s 2016 Greenhouse Gas Emissions Reference Case.

The Government of Canada’s target for these regulations is to reduce emissions by 40 to 45% below the 2012 level by 2025. Using the National Energy Board’s forecast of future production, these regulations require emission reductions that are estimated to achieve just over a 40% reduction in methane emission in 2025, compared to the 2012 reference year. The Government of Canada will track actual production and evaluate the regulatory impact by province over time.

Between 2018 and 2035, the total greenhouse gas emission reductions attributed to the regulations are estimated to be approximately 232 million tonnes of carbon dioxide equivalent.

Using the Social Cost of Methane and Social Cost of Carbon to estimate the economic value of avoided climate change damages at the global level, these reductions are valued at $11.6 billion. The total compliance costs attributable to the proposed regulations are estimated to be $3.9 billion over the same 18-year period. These compliance costs would be offset, in part, by the recovery of 351 petajoules of natural gas with a market value of $1 billion. The regulations are expected to result in net benefits of $8.9 billion.

Regional impact and equivalency

The actual emission reductions these regulations deliver will vary by sector and by province. For example, in British Columbia, natural gas production dominates the oil and gas sector, so the sections of the regulations addressing fugitive emissions and pneumatic equipment will have proportionately more impact. In Saskatchewan, the heavy oil sector will be more impacted by the venting restrictions in the regulations.

Provinces and territories can put in place methane regulations that make sense for their circumstances, provided they can clearly demonstrate emission reductions equivalent to the federal measures. The federal methane regulations provide a backstop to ensure that Canada’s objective of a 40-45 percent methane emission reduction from oil and gas will be achieved. Using National Energy Board production forecasts, Environment and Climate Change Canada’s modelling of the regulations finds annual reductions in methane emissions of about 21 million tonnes (carbon dioxide equivalent) when the regulations are in full force.

Environment and Climate Change Canada is open to discussing the establishment of equivalency agreements under the Canadian Environmental Protection Act with interested provinces. Assessment of equivalency would be based on a comparison of the emissions impacts of the respective federal and provincial regimes, based on production and emission forecasts that are updated annually. In the event that a province wishes to negotiate an equivalency agreement, the Government of Canada will publish an assessment of the emission impacts expected from the federal regulations in that province to inform those negotiations.

Discussions of potential equivalency agreements are an independent regulatory process, which would have a separate Regulatory Impact Analysis Statement. In that effort, consideration for the provincial regulatory approach could include such factors as:

  • validation of the data reported to provinces
  • provincial procedures for quantification and assumptions regarding combustion efficiency of fuel gas
  • provincial requirements for measurement, monitoring and reporting consistent with specific provincial regulatory approaches (fleet averages).

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