Detailed narrative
Record corporate production driven by organic growth plus acquisitions
Q3 2025 corporate production hit a record ~1.62 million BOE/d, the second production record of the year, up ~257,000 BOE/d or 19% versus Q3 2024. Both liquids (~1.18 million bbl/d) and natural gas (~2.7 Bcf/d) set records. Growth reflected organic drilling success plus accretive acquisitions closed over the prior 12 months — the December 2024 AOSP additional interest and Duvernay assets, the Q2 2025 Palliser Block, and Q3 2025 liquids-rich Montney assets in the Grande Prairie area.
Management framed the step-up as capital-efficient, with operating capital held flat at ~$5.9B.
Oil sands mining & upgrading — record utilization and industry-leading cost
Oil sands mining and upgrading averaged 581,136 bbl/d of SCO, up ~83,500 bbl/d or 17% YoY, reflecting the AOSP interest acquired in December 2024 plus strong operations that drove ~104% utilization. Operating costs remained industry-leading at $21.29/bbl of SCO. The November 1 AOSP swap with Shell took CNQ to 100% ownership and operatorship of the Albian mines (retaining a non-operated 80% interest in the Scotford Upgrader and Quest), adding ~31,000 bbl/d of zero-decline bitumen and enabling equipment/parts integration across adjacent mines.
Thermal in situ and conventional heavy oil execution
Thermal in situ averaged 274,752 bbl/d, up slightly YoY, with operating costs of $10.35/bbl (down 2% YoY). Pad development advanced: a Primrose CSS pad began drilling (production H2 2026), a Jackfish SAGD pad came on in July, a 5-well-pair Kirby SAGD came on in late October, and two Pike SAGD pads were tied into Jackfish (first pad Jan 2026, second Q2 2026).
Kirby North commercial-scale solvent SAGD SOR reductions and solvent recoveries are meeting expectations. Primary heavy crude oil averaged 87,705 bbl/d (+14% YoY) at $16.46/bbl (down 12%), driven by multilateral drilling on ~3 million net acres.
North American light oil and natural gas expansion
North American light crude oil and NGL production averaged 180,100 bbl/d, up 69% or ~74,000 bbl/d YoY, driven by the Duvernay acquisition, Palliser Block light oil, and new Montney volumes, at $12.91/bbl operating cost (down 6%). North American natural gas averaged ~2.66 Bcf/d, up 30% YoY, on Duvernay/Montney acquisitions and strong liquids-rich drilling, with operating costs of $1.14/Mcf (down from $1.23).
Pelican Lake averaged ~42,100 bbl/d, down 7% YoY on planned maintenance and natural decline, at $9.00/bbl.
Financial results, balance sheet and shareholder returns
Adjusted funds flow was ~$3.9B and adjusted net earnings $1.8B (both non-GAAP). Shareholder returns in the quarter were $1.5B ($1.2B dividends + $300M buybacks); year-to-date returns through Nov 5 reached ~$6.2B. Quarter-end leverage was 0.9x debt-to-EBITDA and 29.8% debt-to-book-capital, with over $4.3B liquidity.
CNQ repaid USD 600M of debt securities and received a new investment-grade BBB+ rating from Fitch. The Board declared a $0.5875 quarterly dividend, extending 25 consecutive years of increases (21% CAGR).
Macro, egress and policy backdrop
Management sees light-heavy differentials holding in the US$10–13/bbl range, supported by TMX spot capacity, stabilized Western markets, and strong Asian demand for Canadian heavy crude. On natural gas, weak AECO pricing and the need for more egress (LNG Canada and future projects) were emphasized over consolidation.
On federal policy, management noted more constructive engagement than under prior leadership but stressed that 'carbon competitiveness' details remain unclear and key to pathways and future growth economics.