Canadian Natural Resources Ltd. press release

Canadian Natural Resources Limited Announces 2026 First Quarter Results

2026-05-07

TSX - Toronto Stock Exchange · Oil · Bitumen · Natural Gas Liquids · Natural Gas · Canada · Corporate Finance

Calgary, Alberta--(Newsfile Corp. - May 7, 2026) - Canadian Natural's (TSX: CNQ) (NYSE: CNQ) President, Scott Stauth, commented on the Company's first quarter results, "We have a long track record of being an effective and efficient operator, while consistently delivering top tier operational and financial performance through a strong focus on continuous improvement. An example of this performance is our industry-leading Oil Sands Mining and Upgrading Q1/26 operating costs of $23.73/bbl (US$17.30/bbl) for our Synthetic Crude Oil ("SCO").

Quarterly production averaged approximately 1,643,000 BOE/d in Q1/26, which included total quarterly liquids production of approximately 1,198,000 bbl/d, 66% of which was SCO, light crude oil and NGLs. We achieved record quarterly North American E&P production for our conventional crude oil and natural gas business of approximately 773,000 BOE/d, consisting of record quarterly liquids production of approximately 329,000 bbl/d and record quarterly natural gas production of 2,668 MMcf/d. Total Company production in Q1/26 delivered year-over-year growth of 4% or approximately 61,000 BOE/d from Q1/25 levels.

Subsequent to quarter end, in April 2026 at our world class Oil Sands Mining and Upgrading assets, we achieved strong monthly production of approximately 630,000 bbl/d and upgrader utilization of 106%. These strong production volumes are high-value, with strong SCO prices at a premium to WTI averaging approximately US$5.70/bbl on the forward strip for the remainder of 2026.

We remain focused on executing our prudent and capital efficient 2026 capital program as outlined in our updated 2026 guidance previously released in March 2026. Our ability to effectively allocate capital across our strong asset base provides us with a unique competitive advantage and when combined with accretive acquisitions creates significant long-term value for our shareholders."

Canadian Natural's Chief Financial Officer, Victor Darel, added, "In Q1/26, we generated adjusted net earnings of $2.4 billion or $1.17 per share, and adjusted funds flow of $4.4 billion or $2.10 per share. We returned approximately $1.5 billion directly to our shareholders in Q1/26, including $1.2 billion in dividends and $0.3 billion in share repurchases.

As previously announced on March 4, 2026, the Board of Directors increased our quarterly dividend, bringing the annualized dividend up to $2.50 per common share, marking 2026 as the 26th consecutive year of dividend increases by Canadian Natural, with a compound annual growth rate ("CAGR") of 20% over that time, demonstrating the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base.

Robust commodity prices in recent months combined with our effective and efficient operations are delivering strong netbacks which accelerates debt reduction, moving our net debt below $16 billion. As a result, we have increased our pace of share repurchases evident by the $309 million of share repurchases in April 2026, which we prudently manage on a forward-looking basis. Our next targeted net debt level of $13 billion approaches faster with increased free cash flow generation, at which time we increase returns to shareholders to 100% of free cash flow."

FIRST QUARTER HIGHLIGHTS

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Generated net earnings of approximately $1.3 billion and adjusted net earnings from operations of $2.4 billion.

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Generated adjusted funds flow of approximately $4.4 billion.

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Direct returns to shareholders totaled approximately $1.5 billion, comprised of $1.2 billion in dividends and $0.3 billion in share repurchases.

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Year to date, up to and including May 6, 2026, the Company has returned a total of approximately $3.2 billion directly to shareholders through $2.5 billion in dividends and $0.7 billion in share repurchases.

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26 consecutive years of dividend growth with a CAGR of 20% over that time.

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Subsequent to quarter end, declared a quarterly cash dividend on its common shares of $0.625 per common share.

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Subsequent to quarter end, share repurchases were significant at approximately $309 million in April 2026.

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Total quarterly production of approximately 1,643,000 BOE/d, an increase of 61,000 BOE/d or 4% from Q1/25 levels.

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Quarterly liquids production of approximately 1,198,000 bbl/d, an increase of 24,000 bbl/d or 2% from Q1/25 levels.

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Record quarterly North American E&P conventional production of approximately 773,000 BOE/d, consisting of record liquids production of approximately 329,000 bbl/d and record natural gas production of 2,668 MMcf/d.

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Record quarterly Jackfish thermal in situ production of approximately 134,000 bbl/d, driven by strong Pike 1 performance, exceeding nameplate capacity of 120,000 bbl/d.

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Oil Sands Mining and Upgrading production averaged approximately 588,000 bbl/d of SCO with industry-leading operating costs of $23.73/bbl (US$17.30/bbl).

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Canadian Natural continues to progress its defined growth plan over the short, medium, and long-term including:

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In the short-term, our Conventional E&P assets provide significant highly capital efficient drill to fill development, including continued drilling of liquids-rich assets and heavy crude oil multilateral wells.

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We are progressing on our medium-term growth projects, with front end engineering in 2026 on both the 30,000 bbl/d Jackfish expansion project and the 70,000 bbl/d Pike 2 project.

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Further, the Company is progressing long-lead equipment items as part of its thermal in situ growth strategy.

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In the long-term, we maintain our growth opportunities in our Oil Sands Mining and Upgrading segment that include the 150,000 bbl/d Jackpine Mine expansion at Albian and the 90,000 bbl/d Horizon In-Pit Extraction Plant and Paraffinic Froth Treatment expansion.

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These projects remain on hold as we wait for greater certainty on more effective and efficient regulatory policies combined with a competitive fiscal framework and egress. When we have that certainty, we will reassess the viability of these projects.

| HIGHLIGHTS | | Three Months Ended | | | | | | | | | | ($ millions, except per common share amounts) | | Mar 31 2026 | | | Dec 31 2025 | | | Mar 31 2025 | | | | Net earnings | $ | 1,348 | | $ | 5,303 | | $ | 2,458 | | | | Per common share | - basic | $ | 0.65 | | $ | 2.55 | | $ | 1.17 | | | | - diluted | $ | 0.64 | | $ | 2.54 | | $ | 1.17 | | | Adjusted net earnings from operations(1) | $ | 2,446 | | $ | 1,711 | | $ | 2,436 | | | | Per common share | - basic(2) | $ | 1.17 | | $ | 0.82 | | $ | 1.16 | | | | - diluted(2) | $ | 1.17 | | $ | 0.82 | | $ | 1.16 | | | Cash flows from operating activities | $ | 3,282 | | $ | 3,768 | | $ | 4,284 | | | | Adjusted funds flow(1) | $ | 4,374 | | $ | 3,748 | | $ | 4,530 | | | | Per common share | - basic(2) | $ | 2.10 | | $ | 1.80 | | $ | 2.16 | | | | - diluted(2) | $ | 2.09 | | $ | 1.79 | | $ | 2.15 | | | Cash flows used in investing activities | $ | 1,949 | | $ | 1,200 | | $ | 1,312 | | | | Net capital expenditures(1) | $ | 2,028 | | $ | 1,237 | | $ | 1,303 | | | | Net capital expenditures(1), excluding net acquisitions | $ | 1,255 | | $ | 1,413 | | $ | 1,285 | | | | Abandonment expenditures | $ | 247 | | $ | 201 | | $ | 188 | | | | Daily production, before royalties | | | | | | | | | | | | Natural gas (MMcf/d) | | 2,670 | | | 2,660 | | | 2,451 | | | | Crude oil and NGLs (bbl/d) | | 1,198,079 | | | 1,215,364 | | | 1,173,804 | | | | Equivalent production (BOE/d)(3) | | 1,643,160 | | | 1,658,681 | | | 1,582,348 | | | | (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. | | | | | | | | | | |

Net earnings of approximately $1.3 billion reflected strong earnings from operations as well as the impacts of share-based compensation, unrealized mark-to-market on the long-term Liquified Natural Gas ("LNG") agreement, and unrealized foreign exchange on US dollar debt, resulting in adjusted net earnings from operations of $2.4 billion.

SHAREHOLDER RETURNS

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On March 10, 2026, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock Exchange ("TSX"), alternative Canadian trading platforms, and the New York Stock Exchange ("NYSE"), up to 182,396,564 common shares, representing 10% of the public float, over a 12-month period commencing March 13, 2026 and ending March 12, 2027, subject to applicable securities laws.

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Year to date, up to and including May 6, 2026, the Company has returned a total of approximately $3.2 billion directly to shareholders through $2.5 billion in dividends and $0.7 billion through the repurchase and cancellation of approximately 11.3 million common shares at a weighted average price of $60.33 per share.

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On May 6, 2026, the Board of Directors approved a quarterly cash dividend of $0.625 per common share, payable on July 7, 2026 to shareholders of record at the close of business on June 19, 2026.

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This dividend represents an annualized dividend of $2.50 per common share which 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.

OPERATIONS REVIEW

North America Oil Sands Mining and Upgrading

| | | Three Months Ended | | | | | | | | | | | Mar 31 2026 | | | Dec 31 2025 | | | Mar 31 2025 | | | Synthetic crude oil production (bbl/d) (1)(2) | | 587,946 | | | 619,901 | | | 595,116 | | | (1) SCO production before royalties and excludes production volumes consumed internally as diesel. (2) Consists of heavy and light synthetic crude oil products. | | | | | | | | | |

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Oil Sands Mining and Upgrading production averaged 587,946 bbl/d of SCO in Q1/26, comparable to Q1/25 levels. Production in Q1/26 reflected third-party natural gas supply restrictions and unplanned maintenance activities, partially offset by the additional working interest in the AOSP mines acquired in Q4/25.

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Oil Sands Mining and Upgrading operating costs are industry leading, averaging $23.73/bbl (US$17.30/bbl) of SCO in Q1/26, an increase of 8% from Q1/25 primarily due to increased maintenance activities.

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At Horizon, the Company is progressing its Naphtha Recovery Unit Tailings Treatment ("NRUTT") project which targets incremental 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 | | | | | | | | | | | Mar 31 2026 | | | Dec 31 2025 | | | Mar 31 2025 | | | Bitumen production (bbl/d) | | 274,674 | | | 266,308 | | | 284,706 | | | Net bitumen wells drilled | | 31 | | | 25 | | | 18 | | | Net successful bitumen wells drilled | | 30 | | | 24 | | | 18 | | | Success rate | | 97% | | | 96 % | | | 100 % | |

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Thermal in situ production averaged 274,674 bbl/d in Q1/26, a decrease of 4% from Q1/25 levels, primarily due to the cyclical nature of Primrose and natural field declines, partially offset by pad additions at Pike 1.

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Jackfish achieved record quarterly production of 134,396 bbl/d in Q1/26 as a result of strong production from the two new Steam Assisted Gravity Drainage ("SAGD") pads at Pike 1 that continue to exceed expectations.

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Thermal in situ operating costs averaged $12.59/bbl (US$9.18/bbl) in Q1/26, an increase of approximately 12% compared to $11.23/bbl (US$7.83/bbl) in Q1/25, primarily due to the cyclic nature of Primrose.

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Subsequent to quarter end, the Company successfully completed a planned turnaround at one of its Jackfish facilities in April 2026, impacting Q2/26 average production by approximately 9,300 bbl/d.

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As part of the Company's defined short-term growth strategy, Canadian Natural has decades of robust capital efficient drill to fill growth opportunities on its long life low decline thermal in situ assets, which we continue to develop in a disciplined manner to deliver safe and reliable thermal in situ production.

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At Pike 1, the second new pad came on production in late-March 2026 and continues to ramp up. Current combined production from the two new Pike 1 pads is approximately 44,000 bbl/d and continues to exceed expectations, with a Steam to Oil Ratio ("SOR") of approximately 1.8x.

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As a result of strong performance from the Pike 1 pads and through facility optimization including pipeline interconnectivity and debottlenecking, Jackfish is exceeding its facility nameplate capacity of 120,000 bbl/d by approximately 14,000 bbl/d on average in the quarter.

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At Primrose, the Company completed drilling a Cyclic Steam Stimulation ("CSS") pad in February 2026 with production targeted to come on in Q3/26. The Company is drilling two additional CSS pads which are targeted to come on production in 2027.

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At Kirby, the Company is planning to commence drilling a SAGD pad in mid-May 2026, which is targeted to come on production in 2027.

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As part of Canadian Natural's defined medium-term growth strategy, front end engineering is progressing in 2026 on both the 30,000 bbl/d Jackfish expansion project and the 70,000 bbl/d Pike 2 growth project.

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The Company is progressing long-lead equipment items as part of its thermal in situ growth strategy.

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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 Greenhouse Gas ("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.

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The Company continues to operate the commercial scale solvent SAGD pad at Kirby North and the solvent enhanced steam flood pilot at Primrose. An additional solvent SAGD pilot at Kirby South is targeting to begin injection in Q2/26 to evaluate additional future commercial development opportunities.

| Crude oil and NGLs - excluding Thermal In Situ Oil Sands | | | | | | | | | | | | | Three Months Ended | | | | | | | | | | | Mar 31 2026 | | | Dec 31 2025 | | | Mar 31 2025 | | | Crude oil and NGLs production (bbl/d) | | 328,591 | | | 319,189 | | | 276,532 | | | Net crude oil wells drilled | | 83 | | | 90 | | | 57 | | | Net successful crude oil wells drilled | | 83 | | | 90 | | | 56 | | | Success rate | | 100% | | | 100 % | | | 98 % | |

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Record North America E&P liquids production, excluding thermal in situ, of 328,591 bbl/d was achieved in Q1/26, an increase of 19% or approximately 52,000 bbl/d from Q1/25 levels. This record reflects opportunistic acquisitions completed in 2025 and Q1/26, and strong organic growth from heavy crude oil multilaterals, light crude oil and NGLs, partially offset by natural field declines.

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Primary heavy crude oil production averaged 93,824 bbl/d in Q1/26, an increase of 10% or approximately 8,200 bbl/d from Q1/25 levels, reflecting strong drilling results from the Company's multilateral wells.

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Canadian Natural's highly successful multilateral drilling program continues to unlock opportunity on our 3 million net acres of high quality, multizone land throughout our primary heavy crude oil assets.

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Operating costs in the Company's primary heavy crude oil operations averaged $16.13/bbl (US$11.76/‍bbl) in Q1/26, a decrease of 11% from Q1/25 levels, primarily reflecting lower operating cost multilateral production.

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Pelican Lake production averaged 40,548 bbl/d in Q1/26, a decrease of 6% from Q1/25 levels, reflecting the low natural field declines from this long life low decline polymer flood asset.

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Operating costs at Pelican Lake averaged $10.31/bbl (US$7.52/bbl) in Q1/26, an increase of 6% over Q1/25 levels primarily due to lower production volumes.

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Record quarterly production of 194,219 bbl/d was achieved in North America light crude oil and NGLs in Q1/26, an increase of 31% or approximately 46,000 bbl/d from Q1/25 levels, primarily reflecting acquisitions and strong drilling results.

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Operating costs in the Company's North America light crude oil and NGLs operations averaged $12.73/‍‍bbl (US$9.28/bbl) in Q1/26, a decrease of 3% from Q1/25 levels, primarily reflecting higher production volumes.

| North America Natural Gas | | | | | | | | | | | | | Three Months Ended | | | | | | | | | | | Mar 31 2026 | | | Dec 31 2025 | | | Mar 31 2025 | | | Natural gas production (MMcf/d) | | 2,668 | | | 2,657 | | | 2,436 | | | Net natural gas wells drilled | | 24 | | | 20 | | | 19 | | | Net successful natural gas wells drilled | | 24 | | | 20 | | | 19 | | | Success rate | | 100% | | | 100 % | | | 100 % | |

Record quarterly North America natural gas production averaging 2,668 MMcf/d was achieved in Q1/26, an increase of 10% from Q1/25 levels, primarily reflecting acquisitions completed in 2025 and Q1/26, partially offset by natural field declines. North America natural gas operating costs averaged $1.23/Mcf in Q1/26.

International Exploration and Production

| | | Three Months Ended | | | | | | | | | | | Mar 31 2026 | | | Dec 31 2025 | | | Mar 31 2025 | | | Crude oil production (bbl/d) | | 6,868 | | | 9,966 | | | 17,450 | | | Natural gas production (MMcf/d) | | 2 | | | 3 | | | 15 | |

International E&P crude oil production volumes averaged 6,868 bbl/d in Q1/26, a decrease of 61% compared to Q1/25 levels. The decrease reflected the temporary suspension of production at Baobab in Offshore Africa due to planned maintenance on its floating production storage and offloading ("FPSO") vessel, which is expected to return to service in early June 2026, planned North Sea abandonments conducted as part of the previously announced decommissioning activities and maintenance.

| Drilling Activity | | Three Months Ended | | | | | | | | | | | | | | March 31, 2026 | | | March 31, 2025 | | | | | | | | | (number of wells) | | Gross | | | Net | | | Gross | | | Net | | | Crude oil (1) | | 118 | | | 113 | | | 75 | | | 74 | | | Natural gas | | 30 | | | 24 | | | 23 | | | 19 | | | Dry | | 1 | | | 1 | | | 1 | | | 1 | | | Subtotal | | 149 | | | 138 | | | 99 | | | 94 | | | Stratigraphic test / service wells | | 540 | | | 540 | | | 484 | | | 462 | | | Total | | 689 | | | 678 | | | 583 | | | 556 | | | Success rate (excluding stratigraphic test / service wells) | | | | | 99% | | | | | | 99 % | | | (1) Includes bitumen wells. | | | | | | | | | | | | |

Canadian Natural drilled a total of 138 net crude oil and natural gas wells in Q1/26, 44 more than in Q1/25.

MARKETING

| | | Three Months Ended | | | | | | | | | | | | Mar 31 2026 | | | | Dec 31 2025 | | | Mar 31 2025 | | | Benchmark Commodity Prices | | | | | | | | | | | | WTI benchmark price (US$/bbl) (1) | $ | 72.17 | | | $ | 59.13 | | $ | 71.42 | | | WCS heavy differential (discount) to WTI (US$/bbl) (1) | $ | (14.12 | ) | | $ | (11.20 | ) | $ | (12.66 | ) | | WCS heavy differential as a percentage of WTI (%) (1) | | 20% | | | | 19 % | | | 18 % | | | Condensate benchmark price (US$/bbl) | $ | 71.65 | | | $ | 57.01 | | $ | 69.89 | | | SCO price (US$/bbl) (1) | $ | 71.75 | | | $ | 57.78 | | $ | 69.07 | | | SCO premium (discount) to WTI (US$/bbl) (1) | $ | (0.42 | ) | | $ | (1.35 | ) | $ | (2.35 | ) | | AECO benchmark price (C$/GJ) | $ | 2.36 | | | $ | 2.22 | | $ | 1.92 | | | Realized Prices | | | | | | | | | | | | Exploration & Production liquids realized price (C$/bbl) (2)(3)(4)(5) | $ | 76.02 | | | $ | 64.42 | | $ | 79.85 | | | SCO realized price (C$/bbl) (1)(3)(4)(5) | $ | 89.68 | | | $ | 75.90 | | $ | 95.52 | | | Natural gas realized price (C$/Mcf) (4) | $ | 3.32 | | | $ | 2.89 | | $ | 3.13 | | | (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. | | | | | | | | | | |