Published
# Canadian Natural Resources Limited (CNQ) — Company Narrative, Second Quarter 2026
Canadian Natural reports in Canadian dollars. Every money amount below is converted to US dollars: flows at the average exchange rate for the period they cover, and balances and forward-looking budget figures at the closing rate on the date stated. Commodity benchmark prices (WTI, Brent, SCO) and operating costs the company states in US dollars are given as the company prints them. Percentage changes are in US-dollar terms unless marked as Canadian-dollar changes.
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## Business
*Source: Annual report on Form 40-F for the year ended December 31, 2025 (Annual Information Form and annual MD&A), accession 0001017413-26-000018.*
Canadian Natural is a Canadian senior independent oil and gas producer. It explores for, develops, produces and sells crude oil, natural gas and natural gas liquids (NGLs), almost all of it from western Canada, with small remaining operations in the UK North Sea and offshore Côte d'Ivoire. Its largest product is synthetic crude oil (SCO), made by mining oil sands bitumen and upgrading it. SCO was 36% of 2025 production on a barrel-of-oil-equivalent basis. Natural gas was 27%, thermal (steam-recovered) bitumen 17%, light and medium crude oil and NGLs 11%, primary heavy crude oil 6% and Pelican Lake heavy crude oil 3%. Crude oil and NGLs brought in 94% of 2025 product sales and natural gas 6%. Revenue depends on selling these barrels against US-dollar benchmarks (WTI, Brent and, for gas, AECO and NYMEX). Product sales were $31.60 billion in 2025. About 1% of crude oil, NGLs and natural gas sales came from outside North America.
The company is organized into five reporting segments:
- **North America Exploration and Production** ($15.37 billion of 2025 product sales). This covers conventional light crude oil and NGLs, liquids-rich natural gas (Montney, Duvernay, the Palliser Block in southern Alberta), primary heavy crude oil drilled largely with multilateral wells, the Pelican Lake polymer flood, and thermal in situ oil sands at Primrose, Kirby, Jackfish and Pike.
- **Oil Sands Mining and Upgrading** ($14.54 billion of 2025 product sales). This is Horizon Oil Sands plus the Athabasca Oil Sands Project (AOSP). After the 2025 asset swap with Shell, the company owns and operates 100% of the AOSP mines (Muskeg River and Jackpine). It keeps a non-operated 80% interest in the Scotford Upgrader and the Quest carbon capture and storage facility.
- **North Sea** and **Offshore Africa** (International E&P). These are a shrinking business. The North Sea is in decommissioning: Ninian South has stopped producing, and production at the T-Block fields is now set to end in the first quarter of 2027. All North Sea reserves were removed from the books at year-end 2025. In Côte d'Ivoire, the company chose not to extend its production sharing contract for the Espoir Field and is working with the government to hand over operatorship in the second half of 2026. It continues at the Baobab Field.
- **Midstream and Refining**. This segment includes the ECHO and Pelican Lake pipeline systems, which carry about 25% of the company's crude oil production to Edmonton and Hardisty, and a 50% interest in an 84-megawatt cogeneration plant at Primrose. It also includes a 50% equity interest in the North West Redwater Partnership (NWRP) bitumen upgrader and refinery. There the company is a 25% toll payer and must pay its share of the debt component of the toll through 2058.
The strategy is to keep a large, balanced, long-life, low-decline asset base and to hold high working interests and operatorship so the company controls costs. Accretive acquisitions in its core areas are a deliberate part of the plan. That plan is what produced today's footprint:
- In December 2024 it bought Chevron's Alberta assets for $6.5 billion: a 20% interest in AOSP and a 70% operated interest in Duvernay light-oil assets.
- In 2025 it bought the Palliser Block in southern Alberta (about 50,000 BOE/d and about 1.1 million net acres) and liquids-rich Montney assets near Grande Prairie (about 32,000 BOE/d).
- On November 1, 2025 it completed the AOSP asset swap with Shell.
The company reports 10,750 full-time-equivalent permanent employees at December 31, 2025.
On marketing, the company has contracted export pipeline capacity of 256,500 bbl/d:
- Trans Mountain Expansion (TMX): 169,000 bbl/d.
- Flanagan South: 77,500 bbl/d.
- Keystone: 10,000 bbl/d.
It also has a 15-year agreement with Cheniere Marketing to supply 140,000 MMBtu/d of natural gas starting in 2030, priced off the Japan-Korea Marker (JKM) less transportation and liquefaction.
At December 31, 2025, company gross total proved reserves were 15,910 million BOE and proved plus probable reserves were 20,750 million BOE. Total proved reserve additions and revisions replaced 218% of 2025 production.
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## Risk factors
*Source: 2025 Annual Information Form ("Risk Factors") and annual MD&A ("Risks and Uncertainties"), Form 40-F, accession 0001017413-26-000018.*
- **Commodity prices and heavy-oil differentials.** Results are highly sensitive to crude oil and natural gas prices, which depend on OPEC+ supply, geopolitical conflict and pipeline capacity. About 27% of 2025 production was heavy crude oil and bitumen, which sells at a discount to light benchmarks, so a wider differential cuts realized prices directly. Lower forecast prices can also force write-downs of property, plant and equipment.
- **Canada–US trade.** At the time of the annual filing, the US imposed 10% tariffs on Canadian products that do not meet the Canada-United States-Mexico Agreement rules of origin, and further tariffs were possible. The company markets heavily into the US, so trade action affects price, its supply chain and currency.
- **Climate regulation and carbon costs.** Possible federal emissions caps, carbon pricing (Alberta's TIER system, set to rise to a minimum effective credit price of about $94.80 per tonne, at the December 31, 2025 rate, under the November 2025 federal–Alberta MOU), methane rules and clean-fuel rules could raise capital and operating costs for the oil sands in particular. The MOU's benefits depend on final agreements that may not be reached.
- **Market access.** Production moves on third-party pipelines. Constraints, tariffs or export taxes could limit volumes and widen discounts. Opposition to higher-carbon supply could delay pipeline approvals.
- **Operational concentration in oil sands mining and upgrading.** The integrated mine–extraction–upgrader chain is exposed to outages, turnarounds and cost overruns. Wildfires, floods, drought and extreme weather are physical risks across the asset base.
- **Reserves replacement and estimation.** Production declines without continued investment or acquisitions. Reserve estimates depend on price, cost and technical assumptions and can be revised materially.
- **Project execution.** Delays or cost overruns from labour, materials, regulation, weather or tariffs can make projects uneconomic.
- **Liquidity and capital access.** Funding depends on cash flow, credit ratings and capital markets. Lenders and insurers adopting stricter decarbonization policies could raise the cost of capital or insurance.
- **Abandonment and international exposure.** North Sea decommissioning costs have already exceeded budget. Offshore Africa brings political, fiscal, currency-control and local-content risk. UK oil and gas profits face a combined tax rate of 78% under the Energy Profits Levy.
- **Legal and disclosure risk.** Amendments to Canada's Competition Act on environmental claims ("greenwashing") create penalty and litigation exposure. The company has removed some public climate communications in response.
- **Cybersecurity and AI.** A cyber incident could disrupt operations or expose data, and insurance may not cover all losses.
- **Shareholder returns not guaranteed.** The Board reviews the dividend policy and the free-cash-flow allocation policy, which funds buybacks, and either can change.
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## Management's discussion: fiscal 2025
*Source: annual MD&A for the year ended December 31, 2025, Form 40-F, accession 0001017413-26-000018.*
**Results.** 2025 was a year of record volumes but lower oil prices.
- **Production** before royalties averaged a record 1,570,757 BOE/d, up 15%. Crude oil and NGLs rose 14% to a record 1,146,175 bbl/d, and natural gas rose 19% to 2,547 MMcf/d.
- **Product sales** rose to $31.60 billion, up 4.3% in US-dollar terms and 6.4% in Canadian dollars.
- **Net earnings** were $7.74 billion, against $4.46 billion in 2024. They included $2.42 billion of non-operating income after tax, driven mainly by the AOSP asset swap.
- **Adjusted net earnings from operations**, which strip that out, were $5.33 billion: down 1.6% in US-dollar terms and essentially flat (up 0.4%) in Canadian dollars.
- **Cash flow** from operating activities was $10.81 billion, and adjusted funds flow was $11.06 billion.
Management attributed the improvement to:
- higher Oil Sands Mining and Upgrading volumes, after a full year of the Chevron interests;
- higher North America crude oil and NGLs volumes from acquisitions and drilling;
- higher natural gas prices and volumes.
These gains were partly offset by lower realized SCO and crude oil prices. WTI averaged $64.77 per barrel, against $75.72 in 2024, as non-OPEC+ and OPEC+ supply outran demand. The WCS heavy differential narrowed to $11.10 from $14.73 with a full year of TMX capacity.
**AOSP asset swap.** On November 1, 2025 the company gave Shell a 10% non-operated interest in Scotford and Quest and received Shell's remaining 10% of the AOSP mines plus additional oil sands leases. It recognized a total gain of $3.58 billion. Almost all of that is a non-cash gain from remeasuring its existing 90% mine interest to fair value.
**International write-downs.** Pre-tax recoverability charges of $1.27 billion reflect several decisions:
- a competitive tender pushed estimated North Sea abandonment costs above budget;
- the T-Block fields were judged no longer economic;
- the company decided not to extend the Espoir contract and not to develop Kossipo offshore Côte d'Ivoire.
**Capital and returns.** Net capital expenditures fell to $4.71 billion from $10.53 billion in 2024, which had included the Chevron acquisition. The company bought back 33,480,000 shares for $1.05 billion and declared dividends of $1.68 per share. On March 4, 2026 the Board raised the quarterly dividend 6% in Canadian-dollar terms. The 2026 operating capital budget, announced December 16, 2025, was set at about $4.59 billion (converted at the December 31, 2025 rate) and targeted production growth of about 3%.
**Balance sheet.** Long-term debt, net was $11.63 billion at December 31, 2025, and debt to book capitalization was 26%, inside management's 25%–45% range. Liquidity was about $4.62 billion including cash. During 2025 the company:
- repaid two $600 million US-dollar note issues (3.90% and 2.05%);
- issued three series of Canadian medium-term notes in December (3.30% due 2028, 3.75% due 2031 and 4.55% due 2036);
- extended its revolving credit facilities to 2027 and 2029.
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## Current quarter: three and six months ended June 30, 2026
*Source: interim results on Form 6-K filed August 6, 2026, accession 0001017413-26-000043 (results release, MD&A and unaudited interim financial statements).*
**Operations: records almost everywhere.** Total production before royalties was a record 1,676,754 BOE/d, up 18% from the second quarter of 2025. Liquids were a record 1,248,889 bbl/d, up 23%, and 67% of them were higher-value SCO, light crude oil and NGLs. The main contributors were:
- **Oil Sands Mining and Upgrading:** a record 624,754 bbl/d of SCO, up 35%, with upgrader utilization of 106%. The gain reflects the extra AOSP mine interest from the swap and a Scotford turnaround in the prior-year quarter. Operating costs were $16.03 per barrel, down 16% in Canadian-dollar terms, and the segment earned its highest quarterly netback ever, about $56.36 per barrel.
- **Thermal in situ:** 275,607 bbl/d. Jackfish set a record of 136,381 bbl/d, above its 120,000 bbl/d nameplate capacity. The two new Pike 1 SAGD pads are currently producing about 46,000 bbl/d at a steam-to-oil ratio of 1.8x.
- **North America conventional liquids:** a record 338,138 bbl/d, up 25%. This came from acquisitions and from multilateral heavy-oil, light-oil and NGL drilling. Light crude oil and NGLs alone reached a record 204,641 bbl/d, up 45%.
- **Natural gas:** 2,567 MMcf/d company-wide, up 7% on the 2025 and 2026 liquids-rich gas acquisitions.
- **International:** production rose to 10,390 bbl/d after the Baobab floating production vessel returned to service in June 2026 following refurbishment. Since then Baobab has produced about 10,000 BOE/d net, about 2,000 BOE/d above budget.
**Prices.** Continued conflict in the Middle East disrupted supply, and oil prices jumped:
- WTI averaged $92.85 per barrel, against $63.71 a year earlier, and Brent averaged $104.51.
- SCO averaged $101.22, a premium of $8.37 to WTI, because refinery demand was strong and western Canadian supply was cut by weather and maintenance.
- The WCS heavy differential widened to $14.62.
- Gas was weaker: the AECO benchmark fell 27% from a year earlier in Canadian-dollar terms, on higher US production and storage and seasonal LNG maintenance.
**Financial results.** The quarter produced the highest adjusted earnings and adjusted funds flow in the company's history:
- Product sales: $12.44 billion, up 77.9%.
- Net earnings: $3.25 billion ($1.57 per basic share), against $1.78 billion ($0.85) a year earlier, up 83.1%.
- Adjusted net earnings from operations: $3.3 billion ($1.59 per basic share), against $1.08 billion.
- Adjusted funds flow: $4.96 billion ($2.38 per basic share), against $2.36 billion.
- Cash flow from operating activities: $4.93 billion.
Management attributed the gains to higher realized prices and volumes. The realized SCO price was $90.88 per barrel, against $63.02, and the realized E&P liquids price was $75.94, against $50.27. Natural gas partly offset this: the realized price fell to $1.48 per Mcf from $1.86. High sulphur prices added net sulphur revenue of about $195.08 million in the quarter and $326.56 million in the first half; the company supplies about 30% of Canada's sulphur.
For the first half, net earnings were $4.25 billion, against $3.49 billion. Adjusted net earnings from operations were $5.09 billion, against $2.79 billion, and adjusted funds flow was $8.16 billion. First-half net earnings include $843.99 million of non-operating losses after tax, almost all of them in the first quarter. These include an unrealized pre-tax first-half loss of $224.97 million on the embedded derivative in the Cheniere gas supply contract, whose fair value was a liability of $258.37 million at June 30, 2026, and foreign-exchange losses from translating US-dollar debt.
**Acquisitions in the half.** The company bought two packages of producing and non-producing crude oil, NGLs and natural gas assets in the Peace River area of Alberta, next to its existing operations. It accounted for both as business combinations:
- **February 2026:** net cash consideration of $554.90 million, subject to final closing adjustments. The assets included exploration and evaluation assets and property, plant and equipment, and the company assumed asset retirement obligations.
- **June 2026:** net cash consideration of $546.21 million, subject to final closing adjustments, according to the interim financial statements. The results release describes this acquisition as about $549.82 million net of closing adjustments.
**Capital, balance sheet and shareholder returns.**
- **Capital spending.** Net capital expenditures were $1.74 billion in the quarter, including the June acquisition. Abandonment spending continued in North America and the North Sea.
- **Debt.** Long-term debt, net fell to $10.23 billion at June 30, 2026, from $11.63 billion at December 31, 2025: down 12.0% in US-dollar terms and 8.9% in Canadian dollars. Debt to book capitalization improved to 23.7%. Liquidity was about $5.61 billion.
- **Debt due within a year.** This rose to $1.56 billion. The fully drawn non-revolving term credit facility of $2.82 billion matures in December 2027.
- **Shareholder returns.** Returns in the quarter totaled about $2.89 billion: $939.25 million of dividends, $794.75 million of buybacks, and $1.16 billion of net debt reduction.
- **First-half buybacks.** The company repurchased 22,925,000 shares for $1.03 billion.
- **Normal Course Issuer Bid.** The bid renewed in March 2026 allows purchases of up to 182,396,564 shares through March 12, 2027.
- **Net debt target.** Management is aiming for a next net debt level of about $9.15 billion (converted at the June 30, 2026 rate). At that level the company says it will raise shareholder returns to 100% of free cash flow.
**Guidance (updated August 2026).** Two things led the company to raise its 2026 production guidance for the second time this year: the June acquisition and strong conventional drilling. The new range is 1,637,000–1,682,000 BOE/d, up 20,000 BOE/d at the midpoint from 1,615,000–1,665,000. Within that:
- Liquids: 1,204,000–1,243,000 bbl/d.
- Natural gas: 2,595–2,635 MMcf/d.
Operating capital is unchanged at about $4.22 billion. The other budget lines, all converted at the June 30, 2026 rate, are:
- Net acquisition capital: raised to $1.07 billion from $538.56 million.
- Total capital: about $5.38 billion, including about $88 million for carbon capture.
- Abandonment spending: about $699.07 million, excluded from capital.
Upcoming work:
- A 35-day turnaround at Horizon starting September 8, 2026, expected to reduce annual average production by about 29,000 bbl/d. This is already in guidance.
- The Horizon naphtha recovery unit tailings treatment project remains on budget for mechanical completion in the third quarter of 2027, adding about 6,300 bbl/d of SCO.
**New pipeline capacity.** In the second quarter the company signed 20-year agreements for 150,000–165,000 bbl/d of new crude oil pipeline capacity to US markets. Service is expected to begin in the fourth quarter of 2028. If all conditions are met, the agreements would add about $352 million to $387.2 million a year of transportation commitments. They depend on the project proponents' final investment decision and on regulatory approvals, so they are not yet recorded as commitments.
**Corporate.** The company moved its head office within Calgary in June 2026. Dr. G.E. Isaac, President and Chief Operating Officer of Cameco, joined the Board at the May 7, 2026 annual meeting. In the first quarter the company cancelled the small portion of its syndicated revolving credit facility that was due in June 2027, so the whole facility now matures in June 2029.
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## Subsequent events
*Source: interim results on Form 6-K, accession 0001017413-26-000043 (results release, MD&A and interim financial statements note 11), and dividend announcement on Form 6-K, accession 0001017413-26-000045, both filed August 6, 2026.*
The interim filing reports the following events after June 30, 2026. It reports no acquisitions, divestitures or new debt financings after the period end. The June 2026 Peace River acquisition closed within the quarter.
- **Trilateral MOU (July 2026).** The Oil Sands Alliance, the Government of Alberta and the Government of Canada signed a memorandum of understanding. It sets out a possible regulatory and fiscal framework to support the industry's competitiveness. Definitive agreements are targeted for November 2026. Until they are signed, the company is holding all of its medium- and long-term growth projects:
- Jackfish expansion: 30,000 bbl/d.
- Pike 2: 70,000 bbl/d.
- A new Jackpine mine at Albian: 150,000 bbl/d.
- A new in-pit extraction plant and paraffinic froth treatment at Horizon: 90,000 bbl/d.
- **Share repurchases.** From July 1 through August 4, 2026, the company bought back 7,500,000 common shares at a weighted average of $43.57 per share, for $333.32 million including tax. Year to date through August 5, 2026, direct returns to shareholders were about $4.12 billion: $2.75 billion of dividends and $1.37 billion of buybacks, covering about 30.7 million shares at an average of $44.46. Shares outstanding were 2,061,500,000 on August 4, 2026, down from 2,068,840,000 at June 30.
- **Dividend.** On August 5, 2026 the Board declared a quarterly dividend of $0.45 per common share ($1.78 annualized), payable October 2, 2026 to shareholders of record on September 11, 2026. The company says 2026 is its 26th consecutive year of dividend increases, with a 20% compound annual growth rate in Canadian-dollar terms.
- **Operations.** A newly drilled cyclic steam stimulation pad at Primrose began production in July 2026. Two more Primrose pads and a Kirby SAGD pad are targeted to start up in 2027.