AER Revises Manual 015 Flare Measurement Rules, Requiring Biweekly Inspections and Unlit Gas Reporting by 2030

The Alberta Energy Regulator released Bulletin 2026-34 on August 6, 2026, issuing a revised edition of Manual 015. The manual governs methane emissions measurement from flaring, incinerating, and venting across Alberta's upstream petroleum sector. It brings Manual 015 into alignment with Directive 060, which the AER implemented on March 27, 2026. All upstream petroleum companies operating wells and facilities in Alberta must comply.

Five Changes in the Revised Manual 015

The revised manual introduces five operational requirements that expand how operators measure, inspect, and report flare and vent emissions.

• Unlit flare gas reclassified as venting: Gas escaping from a non-igniting flare now counts toward the operator's total vent volume under a new AER estimation equation.
• Monthly unlit flare reporting (January 1, 2030): Operators must submit monthly volume reports for unlit flare gas at their wells and facilities.
• Biweekly fugitive emissions screenings (January 1, 2030): Operators must screen all active flares for fugitive emissions every two weeks.
• Formal flare inspections (January 1, 2030): Any permanent or temporary flare installed, replaced, or relocated after that date requires a documented inspection.
• Glycol dehydrator vent gas reporting: Vented gas from glycol dehydrators must now be reported under Directive 039, closing a gap in Alberta's methane accounting.

Counting Unlit Flares as Venting Events

The reclassification of unlit flare gas as a venting event is the most consequential change in the revised manual. Under the prior methodology, gas escaping from a failed or non-igniting flare did not count against a facility's vent volume total under Directive 060. Under Manual 015's new estimation equation, those volumes enter the vent ledger directly, alongside normally vented gas already tracked. Operators running facilities with high flare cycle rates or aging ignition systems will see their reported vent totals increase, not because actual emissions rose, but because the accounting methodology now captures previously unmeasured volumes.

The practical implication is that some facilities may find themselves closer to Directive 060's vent limits than their prior records suggest. The AER did not disclose what percentage of Alberta flares currently experience unlit events, but the estimation equation's inclusion signals the regulator has determined the volume is material enough to warrant standardized tracking. Operators will need to calculate their unlit flare volumes under the new equation to assess how the revised accounting affects each facility's standing against its vent authorization.

How Alberta's Largest Producers Are Exposed

Cenovus Energy carries broad in-situ oil sands exposure to the new rules. Its Foster Creek and Christina Lake steam-assisted gravity drainage complexes are among Alberta's largest thermal in-situ operations and each runs extensive flare networks. Cenovus also absorbed Husky Energy's Alberta conventional and heavy oil assets in a 2021 acquisition, adding hundreds of well sites and processing facilities to its compliance footprint. Suncor Energy's in-situ thermal assets at Firebag and MacKay River fall within Directive 060's scope, though the company's Syncrude open-pit mining complex does not, as Directive 060 excludes oil sands mining operations.

Imperial Oil, 70% owned by ExxonMobil, operates Cold Lake heavy oil production in Alberta using cyclic steam stimulation, placing the facility within Manual 015's updated scope. ARC Resources, producing approximately 410,000 barrels of oil equivalent per day across Montney and Alberta positions, operates gas processing plants at Ante Creek and Kakwa in Alberta that rely on glycol dehydrators. Those plants fall directly within the Directive 039 reporting requirement added by the revised manual. Canadian Natural Resources, one of Alberta's largest upstream producers by output, faces the combined compliance burden of flare inspection, monthly reporting, and glycol dehydrator tracking across a portfolio spanning the province's major producing basins.

The 2030 Compliance Window

The AER set January 1, 2030 as the effective date for most new requirements in the revised Manual 015. Operators have 3.5 years to implement inspection programs, build monthly reporting systems, and establish record retention for screening documentation. The biweekly screening requirement translates to 26 formal inspection cycles per active flare per year, a cadence that requires dedicated scheduling for operators with large flare inventories. The AER noted that record retention for screening and maintenance documentation is mandatory alongside the inspection itself. Companies seeking regulatory guidance can reach the AER at 1-855-297-8311 or [email protected].