Canadian Natural Resources Limited Announces 2026 Third Quarter Results
Reaching the $13 billion net debt target shifts the company's targeted free cash flow allocation to share repurchases.
Sentiment and the balance of points
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Rhea-AI Summary
Canadian Natural Resources (CNQ) reported third-quarter net earnings of $2,997 million and reached its net debt target during the quarter. Net earnings rose from $600 million a year earlier but fell from $4,503 million in Q2/26. Adjusted funds flow was $5,522 million, versus $3,920 million a year earlier and $6,866 million in Q2/26.
Net debt ended September at $12.1 billion. The company now targets 100% of free cash flow for share repurchases, subject to market conditions, with $800 million monthly targeted for November and December 2026. Production averaged 1,651,720 barrels of oil equivalent daily, versus 1,620,261 a year earlier. Horizon's maintenance shutdown ended October 6, seven days ahead of budget. A quarterly dividend of $0.625 per share is payable January 5, 2027, to holders of record December 15, 2026.
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Hollow bars mark forward-looking points. How the balance works
Positive
- Moderate pointQ3 net earnings of $2,997 million exceeded $600 million a year earlier but declined from $4,503 million in Q2/26.
- Moderate pointQ3 adjusted earnings of $3,427 million exceeded $1,801 million a year earlier but fell from $4,568 million in Q2/26.
- Moderate pointQ3 operating cash flow reached $7,010 million, versus $3,940 million a year earlier and $6,823 million in Q2/26.
- Moderate pointQ3 adjusted funds flow of $5,522 million exceeded $3,920 million a year earlier but declined from $6,866 million in Q2/26.
- Moderate pointNet debt fell approximately $2.4 billion in Q3/26 to $12.1 billion, below the $13 billion target.
- Moderate point. Forward-looking: it has not happened yet and may not happen.100% of free cash flow is now targeted for share repurchases, subject to market conditions.
- Moderate pointApproximately $1.6 billion in Q3/26 share repurchases accompanied $1.3 billion in dividends. 1.6% of market cap
- Moderate pointApproximately 58.2 million shares were repurchased and cancelled through November 4 for $3.8 billion, averaging $65.85 per share. 3.7% of market cap
- Moderate pointQ3 production of 1,651,720 barrels of oil equivalent daily exceeded 1,620,261 a year earlier but trailed 1,676,754 in Q2/26.
25 minor points
- Minor pointQ3 basic earnings per share of $1.46 compared with $0.29 a year earlier and $2.17 in Q2/26.
- Minor pointQ3 adjusted basic earnings per share of $1.67 compared with $0.86 a year earlier and $2.20 in Q2/26.
- Minor pointQ3 adjusted funds flow per basic share of $2.68 compared with $1.88 a year earlier and $3.30 in Q2/26.
- Minor point. Forward-looking: it has not happened yet and may not happen.$800 million monthly share repurchases are targeted for both November and December 2026.
- Minor pointQ3 liquids production of 1,217,178 barrels daily exceeded 1,175,604 a year earlier but trailed 1,248,889 in Q2/26.
- Minor pointRecord thermal production of 299,632 barrels daily increased approximately 25,000 barrels daily, or 9%, year over year.
- Minor pointRecord conventional North American liquids production of approximately 358,000 barrels daily rose 16% year over year.
- Minor pointJackfish production reached a quarterly record of 143,039 barrels daily, approximately 23,000 above facility nameplate capacity.
- Minor pointPike 1's two new pads currently produce approximately 46,500 barrels daily with a steam-to-oil ratio of 1.7x.
- Minor pointThermal operating costs fell approximately 2% to $10.19 per barrel from $10.35 in Q3/25.
- Minor pointHorizon maintenance finished in 28 days on October 6, seven days earlier than budgeted.
- Minor point. Forward-looking: it has not happened yet and may not happen.Approximately 23,000 additional barrels daily of Q4/26 synthetic crude production are expected versus budget following early maintenance completion.
- Minor pointCurrent mining and upgrading production averages approximately 640,000 barrels daily following the Horizon shutdown.
- Minor point. Forward-looking: it has not happened yet and may not happen.Three-year Horizon maintenance intervals are targeted, adding 5,000 barrels daily to average capacity over that period.
- Minor point. Forward-looking: it has not happened yet and may not happen.Total mining and upgrading capacity increases to approximately 597,000 barrels daily under the targeted maintenance cycle.
- Minor point. Forward-looking: it has not happened yet and may not happen.Horizon tailings treatment project remains on budget, targeting approximately 6,300 incremental barrels daily following Q3/27 mechanical completion.
- Minor point. Forward-looking: it has not happened yet and may not happen.Two Primrose pads are targeted to begin production in Q1/27 and Q2/27.
- Minor point. Forward-looking: it has not happened yet and may not happen.A Kirby pad under drilling is targeted to begin production in Q3/27.
- Minor pointSynthetic crude pricing averaged US$6.65 per barrel above WTI in Q3/26.
- Minor pointSulphur contributed approximately $0.5 billion in pre-tax net revenue in Q3/26 and $0.9 billion year to date.
- Minor pointNine-month net earnings rose to $8,848 million from $5,517 million; basic earnings increased to $4.27 from $2.64.
- Minor pointNine-month adjusted earnings rose to $10,441 million from $5,733 million; adjusted basic earnings increased to $5.04 from $2.74.
- Minor pointNine-month operating cash flow rose to $17,115 million from $11,338 million a year earlier.
- Minor pointNine-month adjusted funds flow rose to $16,762 million from $11,712 million; basic per-share flow increased to $8.08 from $5.59.
- Minor pointNine-month production rose to 1,657,243 barrels of oil equivalent daily from 1,541,127 a year earlier.
Negative
- Moderate pointQ3 mining and upgrading production fell 7% year over year to 543,089 barrels daily, reflecting Horizon maintenance.
- Moderate pointQ3 capital spending excluding net acquisitions rose to $1,885 million from $1,318 million a year earlier.
- Moderate pointDefinitive agreements remain pending under the government-industry memorandum needed to clarify assessment of potential growth projects.
- Minor pointHorizon maintenance reduced Q3/26 production by approximately 75,000 barrels daily.
- Minor pointQ3 natural gas production declined to 2,607 million cubic feet daily from 2,668 a year earlier.
3 minor points
- Minor pointQ3 mining and upgrading operating costs averaged $25.80 per barrel, reflecting lower production during maintenance.
- Minor pointNine-month net capital expenditures rose to $6,316 million from $5,342 million a year earlier.
- Minor pointQ3 abandonment spending rose to $248 million from $189 million; nine-month spending increased to $677 million from $570 million.
News Explained
Horizon’s targeted three-year cycle carries a stated five-thousand-barrel-per-day average-capacity gain; NRUTT targets six-thousand-three-hundred barrels per day after third-quarter 2027 completion.
Canadian Natural says it completed the Horizon turnaround on
The company is targeting major Horizon turnarounds every three years; it says this would increase average production capacity over the three-year period by 5,000 bbl/d, bringing total Oil Sands Mining and Upgrading capacity to approximately 597,000 bbl/d.
At Horizon, the NRUTT project remains on track, with mechanical completion targeted for Q3/27 and incremental annual production of approximately 6,300 bbl/d targeted after completion.
Key Figures
- Adjusted net earnings from operations
- $3,427 million
- Q3/26
- Adjusted funds flow
- $5,522 million
- Q3/26
- Net earnings
- $2,997 million
- Q3/26
- Shareholder returns
- $5.3 billion
- Q3/26
- Share repurchase pace
- $800 million per month
- Targeted for November and December 2026
- Net debt
- $12.1 billion
- As of September 30, 2026; below the $13 billion target
- Total production
- 1,651,720 BOE/d
- Q3/26; up 2% from Q3/25
- Quarterly dividend
- $0.625 per common share
- Approved November 4, 2026
Historical Context
-
Reported record Q2 adjusted earnings and funds flow, production, and shareholder returns.
24h Move is the share-price change in the day after each event; other market factors may also have contributed.
Key Terms
steam assisted gravity drainage technical
steam to oil ratio technical
cyclic steam stimulation technical
barrel of oil equivalent technical
non-gaap financial measure financial
AI-generated analysis. How Rhea-AI works. Not financial advice.
Calgary, Alberta--(Newsfile Corp. - November 5, 2026) - Canadian Natural's (TSX: CNQ) (NYSE: CNQ) President, Scott Stauth, commented on the Company's third quarter results, "The strength of our well-balanced and diverse portfolio, combined with our continued focus on safe, effective and efficient operations, delivered another strong quarter. In Q3/26, we achieved production of approximately 1,217,000 bbl/d of liquids and 2.6 Bcf/d of natural gas, totaling approximately 1,652,000 BOE/d, inclusive of a planned turnaround at Horizon, reflecting the quality of our long life low decline asset base and disciplined operating culture.
Our thermal in situ operations achieved record quarterly production of approximately 300,000 bbl/d, an increase of 25,000 bbl/d from Q3/25 levels, driven by continued strong performance from new pads in Pike and Primrose. In our North American Conventional E&P assets, excluding thermal in situ operations, we also achieved record quarterly liquids production of approximately 358,000 bbl/d, an increase of 49,000 bbl/d from Q3/25 levels driven by accretive acquisitions and strong well performance.
At Horizon, subsequent to quarter end, the team safely and successfully completed the planned turnaround in 28 days, seven days earlier than budgeted, through strong execution, adding significant high value, high margin Synthetic Crude Oil ("SCO") production in Q4/26. Following the turnaround, Oil Sands Mining and Upgrading production has been strong, with current rates averaging approximately 640,000 bbl/d. At Horizon, we continue to build on the success of the 2024 reliability enhancement project that enabled us to move major turnarounds to once every two years from annually, and, combined with verified analysis of key parameters from the 2026 turnaround, we are now targeting to extend turnaround intervals at Horizon to once every three years, further increasing reliability and utilization. As a result, Horizon's three year average production capacity increases by an additional 5,000 bbl/d of high margin SCO, bringing total Oil Sands Mining and Upgrading production capacity up to approximately 597,000 bbl/d.
We are pleased to see the federal government designating the proposed West Coast oil pipeline, now known as Pacific Link, as a project of national interest. In addition, the federal government announced the Productivity Mega Deduction ("PMD"), which is expected to enhance competitiveness and investment in Canada. These measures, combined with the trilateral Memorandum of Understanding ("MOU") between the Oil Sands Alliance, the Government of Alberta and the Federal government, will support future economic growth, add additional egress opportunities, provide a clear pathway to reduce Greenhouse Gas ("GHG") emissions and enhance Canada's competitiveness for investment on a global scale. The next important step in this process is finalizing definitive agreements of the MOU, which will provide clarity on assessing our potential growth projects. If industry and governments are able to successfully complete and finalize the definitive agreements of the MOU, the result will be greater investments in the Canadian economy by the oil and gas industry, creating more jobs for Canadians and greater taxes and royalties for governments."
Canadian Natural's Chief Financial Officer, Victor Darel, added, "We achieved our net debt target of
In the first nine months of 2026, we have returned a total of approximately
We delivered strong financial results during the quarter, generating adjusted funds flow of approximately
THIRD QUARTER HIGHLIGHTS
Generated quarterly net earnings of approximately
$3.0 billion and quarterly adjusted net earnings from operations of$3.4 billion .Generated quarterly adjusted funds flow of approximately
$5.5 billion .Captured strong SCO pricing that averaged a US
$6.65 /bbl premium to WTI in the quarter as a result of strong diesel pricing.Strong sulphur pricing and sulphur production contributed pre-tax net revenue of approximately
$0.5 billion (1) in Q3/26 and$0.9 billion through the first nine months of 2026.
The Company achieved its
$13 billion net debt target in Q3/26, with100% of free cash flow now targeted for allocation to share repurchases.Returns to shareholders were significant, totaling approximately
$5.3 billion in Q3/26.Direct returns to shareholders totaled approximately
$2.9 billion in Q3/26, comprised of$1.3 billion in dividends and$1.6 billion in share repurchases.Indirect returns to shareholders, through net debt reductions, totaled approximately
$2.4 billion in Q3/26, with net debt decreasing to$12.1 billion as of September 30, 2026, below our$13 billion net debt target.
Total quarterly production was approximately 1,652,000 BOE/d, an increase of 31,000 BOE/d or
2% from Q3/25 levels.Strong quarterly liquids production was approximately 1,217,000 bbl/d, an increase of 42,000 bbl/d or
4% from Q3/25 levels, inclusive of the planned turnaround at Horizon in Q3/26, which reduced volumes by approximately 75,000 bbl/d for the quarter.Record quarterly thermal in situ production of approximately 300,000 bbl/d, an increase of 25,000 bbl/d or
9% from Q3/25 levels.The two new Steam Assisted Gravity Drainage ("SAGD") pads at Pike 1 continue to exceed expectations, currently producing approximately 46,500 bbl/d at a Steam to Oil Ratio ("SOR") of 1.7x.
Record North American Conventional E&P quarterly liquids production of approximately 358,000 bbl/d, an increase of 49,000 bbl/d or
16% from Q3/25 levels.
Subsequent to quarter end, on October 6, 2026, the team safely and successfully completed the planned turnaround at Horizon in 28 days, seven days earlier than budgeted. This early completion of the turnaround will result in approximately 23,000 bbl/d of additional high margin SCO production in Q4/26 than originally budgeted. Oil Sands Mining and Upgrading production has been strong, with current rates averaging approximately 640,000 bbl/d.
SHAREHOLDER RETURNS
On November 4, 2026, the Board of Directors approved a quarterly cash dividend of
$0.625 per common share, payable on January 5, 2027 to shareholders of record at the close of business on December 15, 2026.This represents an annualized dividend of
$2.50 per common share. Our dividend has grown for 26 consecutive years, demonstrating the confidence that the Board has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base.
Year to date, up to and including November 4, 2026, the Company has returned a total of approximately
$8.9 billion directly to shareholders through$5.1 billion in dividends and$3.8 billion through the repurchase and cancellation of approximately 58.2 million common shares at a weighted average price of$65.85 per share.Included in year to date returns to shareholders is
$728 million of share repurchases in October 2026.
To further enhance visibility, effective immediately, the pace of monthly share repurchases is targeted at
$800 million per month in both November 2026 and December 2026.As we move into 2027, shareholder returns are expected to remain strong as we now target to allocate
100% of free cash flow to share repurchases, subject to market conditions.
(1) Item is a component of 'Other income and revenue' in Note 17 Segmented Information in the Company's consolidated financial statements.
| HIGHLIGHTS | Three Months Ended | Nine Months Ended | ||||||||||||||
| ($ millions, except per common share amounts) | Sep 30 2026 | Jun 30 2026 | Sep 30 2025 | Sep 30 2026 | Sep 30 2025 | |||||||||||
| Net earnings | $ | 2,997 | $ | 4,503 | $ | 600 | $ | 8,848 | $ | 5,517 | ||||||
| Per common share | - basic | $ | 1.46 | $ | 2.17 | $ | 0.29 | $ | 4.27 | $ | 2.64 | |||||
| - diluted | $ | 1.45 | $ | 2.15 | $ | 0.29 | $ | 4.24 | $ | 2.63 | ||||||
| Adjusted net earnings from operations (1) | $ | 3,427 | $ | 4,568 | $ | 1,801 | $ | 10,441 | $ | 5,733 | ||||||
| Per common share | - basic (2) | $ | 1.67 | $ | 2.20 | $ | 0.86 | $ | 5.04 | $ | 2.74 | |||||
| - diluted (2) | $ | 1.65 | $ | 2.19 | $ | 0.86 | $ | 5.01 | $ | 2.73 | ||||||
| Cash flows from operating activities | $ | 7,010 | $ | 6,823 | $ | 3,940 | $ | 17,115 | $ | 11,338 | ||||||
| Adjusted funds flow (1) | $ | 5,522 | $ | 6,866 | $ | 3,920 | $ | 16,762 | $ | 11,712 | ||||||
| Per common share | - basic (2) | $ | 2.68 | $ | 3.30 | $ | 1.88 | $ | 8.08 | $ | 5.59 | |||||
| - diluted (2) | $ | 2.67 | $ | 3.28 | $ | 1.87 | $ | 8.04 | $ | 5.57 | ||||||
| Cash flows used in investing activities | $ | 1,640 | $ | 2,468 | $ | 2,234 | $ | 6,057 | $ | 5,487 | ||||||
| Net capital expenditures (1) | $ | 1,883 | $ | 2,405 | $ | 2,124 | $ | 6,316 | $ | 5,342 | ||||||
| Net capital expenditures (1), excluding net acquisitions | $ | 1,885 | $ | 1,643 | $ | 1,318 | $ | 4,783 | $ | 4,312 | ||||||
| Abandonment expenditures | $ | 248 | $ | 182 | $ | 189 | $ | 677 | $ | 570 | ||||||
| Daily production, before royalties | ||||||||||||||||
| Natural gas (MMcf/d) | 2,607 | 2,567 | 2,668 | 2,615 | 2,510 | |||||||||||
| Crude oil and NGLs (bbl/d) | 1,217,178 | 1,248,889 | 1,175,604 | 1,221,452 | 1,122,859 | |||||||||||
| Equivalent production (BOE/d) (3) | 1,651,720 | 1,676,754 | 1,620,261 | 1,657,243 | 1,541,127 | |||||||||||
| (1) Non-GAAP Financial Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A. (2) Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A. (3) A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, or to compare the value ratio using current crude oil and natural gas prices since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. | ||||||||||||||||
OPERATIONS REVIEW
North America Oil Sands Mining and Upgrading
| Three Months Ended | Nine Months Ended | ||||||||||||||
| Sep 30 2026 | Jun 30 2026 | Sep 30 2025 | Sep 30 2026 | Sep 30 2025 | |||||||||||
| Synthetic crude oil production (bbl/d) (1)(2) | 543,089 | 624,754 | 581,136 | 585,099 | 546,635 | ||||||||||
| (1) SCO production before royalties and excludes production volumes consumed internally as diesel. (2) Consists of heavy and light synthetic crude oil products. | |||||||||||||||
Oil Sands Mining and Upgrading production averaged 543,089 bbl/d of SCO in Q3/26, a decrease of
7% from Q3/25 levels, reflecting the planned turnaround at Horizon, partially offset by the additional working interest acquired in the Albian mines in December 2025.The Company's Oil Sands Mining and Upgrading operating costs are industry leading, averaging
$25.80 /bbl (US$18.44 /bbl) of SCO in Q3/26. Operating costs on a per barrel basis primarily reflect lower production as a result of the turnaround at Horizon.
Subsequent to quarter end, on October 6, 2026, the Company safely and successfully completed the planned turnaround at Horizon in 28 days, seven days earlier than budgeted. This early completion of the turnaround will result in approximately 23,000 bbl/d of additional high margin SCO production in Q4/26 than originally budgeted. Following the turnaround, Oil Sands Mining and Upgrading production has been strong, with current rates averaging approximately 640,000 bbl/d.
At Horizon, we continue to build on the success of the 2024 reliability enhancement project that enabled us to move major turnarounds to once every two years from annually, and, combined with verified analysis of key parameters from the 2026 turnaround, we are now targeting to extend turnaround intervals at Horizon to once every three years, further increasing reliability and utilization.
As a result of moving to a three year turnaround cycle, Horizon's average production capacity over the three year period increases by an additional 5,000 bbl/d of high margin SCO barrels, bringing total Oil Sands Mining and Upgrading production capacity up to approximately 597,000 bbl/d.
The Company's Naphtha Recovery Unit Tailings Treatment ("NRUTT") project at Horizon remains on track with capital on budget and targeted incremental annual production of approximately 6,300 bbl/d of SCO, following mechanical completion in Q3/27.
North America Exploration and Production
| Thermal In Situ Oil Sands | |||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||
| Sep 30 2026 | Jun 30 2026 | Sep 30 2025 | Sep 30 2026 | Sep 30 2025 | |||||||||||
| Bitumen production (bbl/d) | 299,632 | 275,607 | 274,752 | 283,396 | 278,046 | ||||||||||
| Net bitumen wells drilled | 45 | 38 | 11 | 114 | 53 | ||||||||||
Record thermal in situ production of 299,632 bbl/d was achieved in Q3/26, an increase of approximately 25,000 bbl/d or
9% from Q3/25 levels, reflecting strong production from the recently added SAGD pads and the new Cyclic Steam Stimulation ("CSS") pad at Primrose that came on production in July 2026.Jackfish achieved record quarterly production of 143,039 bbl/d in Q3/26, exceeding its facility nameplate capacity by approximately 23,000 bbl/d as a result of strong performance from the Pike 1 pads.
The two new SAGD pads at Pike 1 continue to exceed expectations, currently producing approximately 46,500 bbl/d at a SOR of 1.7x. The Pike 1 SAGD pads are top tier in industry, driven by high-quality resource and continuous improvement in technology and execution.
Thermal in situ operating costs averaged
$10.19 /bbl (US$7.28 /bbl) in Q3/26, a decrease of approximately2% compared to$10.35 /bbl in Q3/25, reflecting higher production, partially offset by higher energy costs.
Canadian Natural has decades of robust, capital efficient drill to fill opportunities across its long life low decline thermal in situ assets. The Company is on track with its 2026 budget, with the following pad additions:
At Primrose, two Cyclic Steam Stimulation ("CSS") pads are targeted to come on production in Q1/27 and Q2/27.
At Kirby, the Company is drilling a SAGD pad, which is targeted to come on production in Q3/27.
Canadian Natural has been piloting solvent enhanced oil recovery technology on certain thermal in situ assets with an objective to increase bitumen production while reducing the SOR and GHG emissions, at the same time optimizing solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
As a result of continued strong production performance from new wells at the Kirby South pilot, the Company is targeting to begin solvent injection using diluent in the first half of 2027.
| Crude oil and NGLs - excluding Thermal In Situ Oil Sands | |||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||
| Sep 30 2026 | Jun 30 2026 | Sep 30 2025 | Sep 30 2026 | Sep 30 2025 | |||||||||||
| Crude oil and NGLs production (bbl/d) | 358,484 | 338,138 | 309,873 | 341,848 | 285,931 | ||||||||||
| Net crude oil wells drilled | 108 | 80 | 78 | 271 | 192 | ||||||||||
Record quarterly North America E&P liquids production, excluding thermal in situ operations, of 358,484 bbl/d was achieved in Q3/26, an increase of approximately 49,000 bbl/d or
16% from Q3/25 levels. This record reflects accretive Charlie Lake light crude oil acquisitions and strong organic growth in heavy crude oil, light crude oil and NGLs.Strong primary heavy crude oil production averaged 95,621 bbl/d in Q3/26, an increase of
9% from Q3/25 levels, reflecting growth in our quick payout, high return multilateral wells.Canadian Natural's highly successful multilateral drilling program, driven by continuous improvement in execution and technology advancements, continues to unlock opportunities on our 3 million net acres of high quality, multizone land throughout our primary heavy crude oil assets.
Operating costs in the Company's primary heavy crude oil operations averaged
$18.02 /bbl (US$12.88 /bbl) in Q3/26, an increase from$16.46 /bbl in Q3/25, reflecting increased weather related road maintenance and higher diesel costs.
In the Company's Pelican Lake polymer flood area, production averaged 45,514 bbl/d in Q3/26, an increase of
8% from Q3/25 levels, reflecting strong results from Driftwood and the long life low decline nature of these assets.Operating costs at Pelican Lake averaged
$10.45 /bbl (US$7.47 /bbl) in Q3/26, an increase from$9.00 /bbl in Q3/25, reflecting increased trucked production from Driftwood.
Record quarterly production of 217,349 bbl/d was achieved in North America light crude oil and NGLs in Q3/26, an increase of approximately 37,000 bbl/d or
21% from Q3/25 levels, primarily reflecting accretive acquisitions and strong drilling results.Operating costs in the Company's North America light crude oil and NGLs operations averaged
$12.85 /bbl (US$9.18 /bbl) in Q3/26, comparable to Q3/25 levels.
| North America Natural Gas | |||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||
| Sep 30 2026 | Jun 30 2026 | Sep 30 2025 | Sep 30 2026 | Sep 30 2025 | |||||||||||
| Natural gas production (MMcf/d) | 2,602 | 2,563 | 2,658 | 2,611 | 2,498 | ||||||||||
| Net natural gas wells drilled | 11 | 23 | 17 | 58 | 58 | ||||||||||
- North America natural gas production averaged 2,602 MMcf/d in Q3/26, a decrease of
2% from Q3/25 levels, reflecting natural field declines partially offset by accretive acquisitions completed in 2026 and strong liquids-rich natural gas drilling results. North America natural gas operating costs averaged$1.14 /Mcf in Q3/26.
International Exploration and Production
| Three Months Ended | Nine Months Ended | ||||||||||||||
| Sep 30 2026 | Jun 30 2026 | Sep 30 2025 | Sep 30 2026 | Sep 30 2025 | |||||||||||
| Crude oil production (bbl/d) | 15,973 | 10,390 | 9,843 | 11,110 | 12,247 | ||||||||||
| Natural gas production (MMcf/d) | 5 | 4 | 10 | 4 | 12 | ||||||||||
International E&P crude oil production volumes averaged 15,973 bbl/d in Q3/26, an increase of
62% compared to Q3/25 levels. The increase reflects the return of production at Baobab in Offshore Africa in June 2026 following completion of the refurbishment of the floating production storage and offloading ("FPSO") vessel, partially offset by the planned North Sea abandonments conducted as part of the previously announced decommissioning activities.At Baobab, the Company commenced its Phase 5 drilling program in September 2026 and is targeting to complete the drilling program in Q3/27.
| Drilling Activity | Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | September 30, 2026 | September 30, 2025 | |||||||||||||||||||||
| (number of wells) | Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||
| Crude oil (1) | 159 | 153 | 92 | 89 | 398 | 385 | 253 | 245 | ||||||||||||||||
| Natural gas | 15 | 11 | 23 | 17 | 74 | 58 | 73 | 58 | ||||||||||||||||
| Subtotal | 174 | 164 | 115 | 106 | 472 | 443 | 326 | 303 | ||||||||||||||||
| Stratigraphic test / service wells | 12 | 12 | 3 | 3 | 573 | 573 | 516 | 493 | ||||||||||||||||
| Total | 186 | 176 | 118 | 109 | 1,045 | 1,016 | 842 | 796 | ||||||||||||||||
| (1) Includes bitumen wells. | ||||||||||||||||||||||||
- Canadian Natural drilled a total of 443 net crude oil and natural gas wells in the first nine months of 2026, 140 more than in the comparable period in 2025.
MARKETING
| Three Months Ended | Nine Months Ended | ||||||||||||||||
| Sep 30 2026 | Jun 30 2026 | Sep 30 2025 | Sep 30 2026 | Sep 30 2025 | |||||||||||||
| Benchmark Commodity Prices | |||||||||||||||||
| WTI benchmark price (US$/bbl) (1) | $ | 85.68 | $ | 92.85 | $ | 64.95 | $ | 83.62 | $ | 66.67 | |||||||
| WCS heavy differential (discount) to WTI (US$/bbl) (1) | $ | (13.86 | ) | $ | (14.62 | ) | $ | (10.36 | ) | $ | (14.20 | ) | $ | (11.07 | ) | ||
| WCS heavy differential as a percentage of WTI (%) (1) | 16 % | 16 % | 16 % | 17 % | 17 % | ||||||||||||
| Condensate benchmark price (US$/bbl) | $ | 82.22 | $ | 95.59 | $ | 63.12 | $ | 83.19 | $ | 65.45 | |||||||
| SCO price (US$/bbl) (1) | $ | 92.33 | $ | 101.22 | $ | 66.26 | $ | 88.51 | $ | 66.66 | |||||||
| SCO premium (discount) to WTI (US$/bbl) (1) | $ | 6.65 | $ | 8.37 | $ | 1.31 | $ | 4.89 | $ | (0.01 | ) | ||||||
| AECO benchmark price (C$/GJ) | $ | 1.47 | $ | 1.43 | $ | 0.94 | $ | 1.75 | $ | 1.61 | |||||||
| Realized Prices | |||||||||||||||||
| Exploration & Production liquids realized price (C$/bbl) (2)(3)(4)(5) | $ | 95.93 | $ | 105.11 | $ | 72.57 | $ | 92.62 | $ | 74.06 | |||||||
| SCO realized price (C$/bbl) (1)(3)(4)(5) | $ | 114.56 | $ | 125.78 | $ | 87.85 | $ | 110.26 | $ | 90.45 | |||||||
| Natural gas realized price (C$/Mcf) (4) | $ | 2.09 | $ | 2.05 | $ | 1.49 | $ | 2.49 | $ | 2.37 | |||||||
| (1) West Texas Intermediate ("WTI"); Western Canadian Select ("WCS"); Synthetic Crude Oil ("SCO"). (2) Exploration & Production crude oil and NGLs average realized price excludes SCO. (3) Pricing is net of blending and feedstock costs. (4) Excludes risk management activities. (5) Non-GAAP ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A. | |||||||||||||||||
Canadian Natural has a balanced and diverse product mix of SCO, light crude oil, NGLs, heavy crude oil, bitumen and natural gas, complemented with a balanced and diverse marketing strategy.
Approximately 776,000 bbl/d or
64% of total liquids production in Q3/26 consisted of SCO, light crude oil and NGLs.The SCO price premium to WTI was strong in Q3/26, averaging US
$6.65 /bbl, primarily driven by strong diesel refining margins and planned seasonal maintenance in the Western Canadian Sedimentary Basin ("WCSB").Current SCO annual average strip pricing in 2026 represents a premium to WTI of approximately US
$5.56 /bbl.
Canadian Natural has increased its committed volumes to 177,750 bbl/d on the Trans Mountain Expansion ("TMX") pipeline, bringing total contracted crude oil export transportation capacity up to 265,250 bbl/d to Canada's west coast and to the United States Gulf Coast, representing approximately
22% of 2026 forecasted liquids production. The egress supports Canadian Natural's long-term sales strategy by targeting diverse refining markets which drive stronger netbacks while also reducing exposure to egress constraints.The North West Redwater refinery,
50% owned by the Company, primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 84,730 bbl/d in Q3/26.Canadian Natural maintains a diversified natural gas marketing strategy. In 2026, the Company is targeting to consume the equivalency of approximately
34% of its forecasted natural gas production in its Oil Sands Mining and Upgrading and thermal operations, with approximately33% targeted to be sold at AECO/Station 2 pricing, and approximately33% targeted to be exported to other North American and international markets capturing higher natural gas prices, maximizing value.Canadian Natural has a long-term natural gas supply agreement with Cheniere Marketing, LLC. ("Cheniere") as part of the Sabine Pass Liquefaction Expansion Project where the Company has agreed to sell 140,000 MMBtu/d of natural gas to Cheniere for a term of 15 years, with delivery anticipated to begin in 2030.
Under the terms of the agreement, Canadian Natural will deliver natural gas to Cheniere in Chicago and receive a Japan Korea Marker ("JKM") index price less deductions for transportation and liquefaction.
ADVISORY
Special Note Regarding Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "focus", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration", or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to the Company's strategy or strategic focus, capital budget, expected future commodity pricing, forecasted or anticipated production volumes, royalties, production expenses, capital expenditures, forecasted and anticipated abandonment expenditures, income tax expenses, and other targets provided throughout this document and Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, including the strength of the Company's balance sheet, the sources and adequacy of the Company's liquidity, and the flexibility of the Company's capital structure, constitute forward-looking statements. Disclosure of plans relating to, and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects ("Primrose"), the Pelican Lake water and polymer flood projects ("Pelican Lake"), the Kirby thermal oil sands project ("Kirby"), the Jackfish thermal oil sands project ("Jackfish"), the Pike thermal oil sands project ("Pike"), and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of crude oil, bitumen, natural gas, natural gas liquids ("NGLs"), or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market; the maintenance of the Company's facilities and any expected return to service dates; the construction, expansion, or maintenance of third-party facilities that process the Company's products; the abandonment and decommissioning of certain assets and the timing thereof; the development and/or deployment of technology and technological innovations (including artificial intelligence ("AI")) and the timely and effective implementation thereof; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; and the materiality of the impact of tax interpretations and litigation on the Company's results, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations, and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives, or expectations upon which they are based will occur. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, bitumen, natural gas, and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.
The forward-looking statements are based on current expectations, estimates, and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance, or achievements of the Company to be materially different from any future results, performance, or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of conflicts in the Middle East and in Ukraine, the restriction or disruption of global trade routes, the impact of changes to US economic policy, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, bitumen, natural gas, and NGLs prices; the impact of the ramp-up of LNG Canada on commodity prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; changes and uncertainties in the international trade environment, including with respect to tariffs, export restrictions, embargoes, and key trade agreements (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded); uncertainty in the regulatory framework governing greenhouse gas emissions including, among other things, financial and other support from various levels of government for climate related initiatives and potential emissions or production caps, and the timing, impact, and success of the implementation of the Memorandum of Understanding ("MOU") entered into between the Government of Canada and the Government of Alberta in November 2025 and the trilateral Memorandum of Understanding ("trilateral MOU") entered into between the Oil Sands Alliance, the Government of Alberta, and the Government of Canada in July 2026, including the execution of definitive agreements and satisfaction of other regulatory, financial and other conditions contemplated thereunder; civil unrest and political uncertainty, including changes in government, actions of or against terrorists, insurgent groups, or other conflict including conflict between states; the ability of the Company to prevent and recover from a cyberattack, other cyber-related crime, and other cyber or AI-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the impact of AI on the Company's business operations; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling, and other equipment; ability of the Company to complete capital programs; the Company's ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting, or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting, or upgrading of the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, bitumen, natural gas and NGLs not currently classified as proved; changes to future abandonment and decommissioning costs; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety, competition, environmental laws and regulations, and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short-, medium-, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.
The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state, and local laws and regulations such as restrictions on production or emissions, the imposition of tariffs, embargoes, or export restrictions on the Company's products (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded), changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations (including the implementation of the MOU and the trilateral MOU). Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this document and the Company's MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity, and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this document or the Company's MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company's estimates or opinions change.
Special Note Regarding Amendments to the Competition Act (Canada)
On June 20, 2024, amendments to the Competition Act (Canada) came into force with the adoption of Bill C-59, An Act to Implement Certain Provisions of the Fall Economic Statement, which impact environmental and climate disclosures by businesses. As a result of these amendments, certain public representations by a business regarding the benefits of the work it is doing to protect or restore the environment or mitigate the environmental and ecological causes or effects of climate change may violate the Competition Act's deceptive marketing practices provisions. Subsequently, on March 26, 2026, the Competition Act was further amended to remove the requirement that businesses substantiate their environmental representations about a business or business activity based on an internationally recognized methodology, and eliminate private rights of action under the revised business-activity greenwashing provision. Notwithstanding these amendments, uncertainty surrounding the interpretation and enforcement of this legislation, which includes any future amendments, may expose the Company to increased litigation and financial penalties, the outcome and impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business, reputation, financial condition, and results.
Special Note Regarding Currency, Financial Information and Production
This document should be read in conjunction with the Company's MD&A and unaudited interim consolidated financial statements (the "financial statements") for the three and nine months ended September 30, 2026, and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2025. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's MD&A and financial statements for the three and nine months ended September 30, 2026 have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("IFRS Accounting Standards").
Production volumes and per unit statistics are presented throughout this document and the Company's MD&A on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil ("6 Mcf:1 bbl"). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this document and the Company's MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, thermal bitumen, and SCO (including mining bitumen). Production on an "after royalties" or "company net" basis is also presented for information purposes only.
Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2025, is available on SEDAR+ at www.sedarplus.ca, and on EDGAR at www.sec.gov. Information in such Annual Information Form and on the Company's website does not form part of and is not incorporated by reference in this document and the Company's MD&A, dated November 4, 2026.
Special Note Regarding Non-GAAP and Other Financial Measures
This document includes references to non-GAAP and other financial measures as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). These financial measures are used by the Company to evaluate its financial performance, financial position, and cash flow and include non-GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS Accounting Standards and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company's non-GAAP and other financial measures included in this document and the Company's MD&A and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below as well as in the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A for the three and nine months ended September 30, 2026 dated November 4, 2026.
Free Cash Flow Allocation Policy
Free cash flow is a non-GAAP financial measure. The Company considers free cash flow a key measure in demonstrating the Company's ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders and to repay or maintain net debt levels, pursuant to the free cash flow allocation policy.
The Company's free cash flow is used to determine the targeted amount of shareholder returns after dividends. The amount allocated to shareholders varies depending on the Company's net debt position.
Free cash flow is calculated as adjusted funds flow less dividends on common shares, net capital expenditures and abandonment expenditures. The Company targets to manage the allocation of free cash flow on a forward-looking annual basis, while managing working capital and cash requirements as needed. Working capital movements, foreign exchange rate changes and other factors may result in shareholder returns varying from free cash flow generated in a particular period. Accordingly, the timing and allocation of shareholder returns may be accelerated, deferred or reallocated between periods at management's discretion.
As of September 30, 2026, the Company's net debt was below its
The Company's free cash flow for the three months ended September 30, 2026 and comparable periods is shown below:
| Three Months Ended | |||||||||
| ($ millions) | Sep 30 2026 | Jun 30 2026 | Sep 30 2025 | ||||||
| Adjusted funds flow (1) | $ | 5,522 | $ | 6,866 | $ | 3,920 | |||
| Less: Dividends on common shares | 1,294 | 1,304 | 1,228 | ||||||
| Net capital expenditures (1) | 1,883 | 2,405 | 2,124 | ||||||
| Abandonment expenditures | 248 | 182 | 189 | ||||||
| Free cash flow | $ | 2,097 | $ | 2,975 | $ | 379 | |||
| (1) Non-GAAP Financial Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A for the three and nine months ended September 30, 2026 dated November 4, 2026. | |||||||||
Long-term Debt, net
Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents.
| ($ millions) | Sep 30 2026 | Jun 30 2026 | Dec 31 2025 | Sep 30 2025 | ||||||||
| Long-term debt | $ | 16,633 | $ | 17,144 | $ | 16,617 | $ | 17,268 | ||||
| Less: cash and cash equivalents | 4,516 | 2,618 | 673 | 113 | ||||||||
| Long-term debt, net | $ | 12,117 | $ | 14,526 | $ | 15,944 | $ | 17,155 |
Breakeven WTI Price
The breakeven WTI price is a supplementary financial measure that represents the equivalent US dollar WTI price per barrel where the Company's adjusted funds flow is equal to the sum of maintenance capital and dividends. The Company considers the breakeven WTI price a key measure in evaluating its performance, as it demonstrates the efficiency and profitability of the Company's activities. The breakeven WTI price incorporates the non-GAAP financial measure adjusted funds flow as reconciled in the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A. Maintenance capital is a supplementary financial measure that represents the capital required to maintain annual production at prior period levels.
Capital Budget
Capital budget (or capital forecast) is a forward-looking non-GAAP financial measure. Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns, and the balancing of project risks and time horizons.
The capital budget (or capital forecast) excludes abandonment expenditures related to the execution of the Company's abandonment and reclamation programs in North America and the North Sea. The Company currently carries an Asset Retirement Obligation ("ARO") liability on its balance sheet for these forecasted future expenditures. Abandonment expenditures are reported before the impact of current income tax recoveries in Canada and the UK portion of the North Sea. The Company is eligible to recover interest related to tax recoveries in the North Sea.
Capital Efficiency
Capital efficiency is a supplementary financial measure that represents the capital spent to add new or incremental production divided by the current rate of the new or incremental production. It is expressed as a dollar amount per flowing volume of a product ($/bbl/d or $/BOE/d). The Company considers capital efficiency a key measure in evaluating its performance, as it demonstrates the efficiency of the Company's capital investments.
CONFERENCE CALL
Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) will be issuing its 2026 Third Quarter Earnings Results on Thursday, November 5, 2026 before market open.
A conference call will be held at 9:00 a.m. ABT / 10:00 a.m. ET on Thursday, November 5, 2026.
Dial-in to the live event:
North America 1-800-717-1738 / International 001-289-514-5100.
Listen to the audio webcast:
Access the audio webcast on the home page of our website, www.cnrl.com.
Conference call playback:
North America 1-888-660-6264 / International 001-289-819-1325 (Passcode: 83801#)
Canadian Natural is a senior crude oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.
| CANADIAN NATURAL RESOURCES LIMITED T (403) 517-6700 F (403) 517-7350 E ir@cnrl.com 400 4 Avenue S.W. Calgary, AB T2P 0J4 www.cnrl.com | ||
| SCOTT G. STAUTH President VICTOR C. DAREL Chief Financial Officer LANCE J. CASSON Manager, Investor Relations Trading Symbol - CNQ Toronto Stock Exchange New York Stock Exchange | ||
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/322620
FAQ
AI-generated questions and answers. How Rhea-AI works. Not financial advice.
What were Canadian Natural Resources' Q3 2026 earnings?
Canadian Natural Resources reported $2,997 million in net earnings, or $1.46 per basic share, for Q3/26. That compares with $600 million, or $0.29 per basic share, in Q3/25 and $4,503 million, or $2.17 per basic share, in Q2/26.
Why do pending government agreements matter for Canadian Natural Resources' growth projects?
Canadian Natural says finalizing definitive agreements under the trilateral memorandum of understanding will provide clarity for assessing potential growth projects. The memorandum involves the Oil Sands Alliance, Alberta's government and the federal government.