Calgary, Alberta--(Newsfile Corp. - November 6, 2025) - Canadian Natural's (TSX:CNQ) (NYSE:CNQ) President, Scott Stauth, commented on the Company's third quarter results, "Operations were strong in Q3/25 as we achieved record quarterly production volumes totaling approximately 1,620 MBOE/d, including records for both liquids and natural gas at 1,176 Mbbl/d and 2,668 MMcf/d respectively. We increased total corporate production by 19% or approximately 257,000 BOE/d from Q3/24 levels, reflecting both accretive acquisitions and organic growth achieved across our asset base over the last 12 months.

Our world class Oil Sands Mining and Upgrading assets continue to achieve strong operational performance as Q3/25 production averaged approximately 581,000 bbl/d of SCO, with strong utilization of 104% and industry leading operating costs of approximately $21 per barrel.

Subsequent to quarter end, we closed the AOSP swap with Shell Canada Limited and affiliates ("Shell") on November 1, 2025, with an effective date of March 1, 2025. Canadian Natural now owns and operates 100% of the Albian oil sands mines and associated reserves and retains a non-operated 80% interest in the Scotford Upgrader and Quest facilities. This generates additional cash flow and adds approximately 31,000 bbl/d of annual, zero decline bitumen production to our portfolio, driving long-term value creation for our shareholders. This swap also enhances our ability to integrate equipment and services across our mining operations, unlocking additional value through continuous improvement initiatives.

Additionally, we increased our annual 2025 corporate production guidance range to 1,560 MBOE/d to 1,580 MBOE/d, while our 2025 operating capital forecast remains unchanged at approximately $5.9 billion while executing additional activity on our increased asset base size."

Canadian Natural's Chief Financial Officer, Victor Darel, added, "Our business model is robust and sustainable, underpinned by a strong balance sheet that provides flexibility through significant liquidity, totaling approximately $4.3 billion as at September 30, 2025. We closed accretive and opportunistic acquisitions in the quarter and remained at similar net debt levels when compared to Q2/25. These are excellent results, highlighting the free cash flow generating capability of our top tier asset base.

In Q3/25, we generated adjusted net earnings of $1.8 billion or $0.86 per share, and adjusted funds flow of $3.9 billion or $1.88 per share. We returned approximately $1.5 billion to our shareholders in the quarter, including $1.2 billion in dividends and $0.3 billion in share repurchases as we continue to execute on our free cash flow allocation policy."

THIRD QUARTER HIGHLIGHTS

Generated net earnings of approximately $0.6 billion and adjusted net earnings from operations of approximately $1.8 billion.
Generated adjusted funds flow of approximately $3.9 billion.
Returns to shareholders totaled approximately $1.5 billion, comprised of $1.2 billion in dividends and $0.3 billion in share repurchases.
- Year to date, up to and including November 5, 2025, the Company has returned a total of approximately $6.2 billion directly to shareholders through $4.9 billion in dividends and $1.3 billion in share repurchases.
- 25 consecutive years of dividend growth with a CAGR of 21% over that time.
  - Subsequent to quarter end, declared a quarterly cash dividend on its common shares of $0.5875 per common share.
Record quarterly corporate production of 1,620,261 BOE/d.
- Significant total BOE production growth of approximately 257,000 BOE/d or 19% from Q3/24 levels reflects accretive acquisitions and organic growth achieved over the last 12 months.
- Record quarterly liquids production of 1,175,604 bbl/d was achieved, an increase of approximately 154,000 bbl/d or 15% from Q3/24 levels.
  - Oil Sands Mining and Upgrading production was strong, averaging 581,136 bbl/d of SCO with upgrader utilization of 104% and industry leading operating costs of $21.29/bbl (US$15.46/bbl) in Q3/25.
Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with approximately $4.3 billion in liquidity⁽¹⁾ as at September 30, 2025. During Q3/25, the Company:
- Repaid US$600 million of US dollar debt securities due in July 2025.
- Received a new long-term investment grade credit rating of BBB+ from Fitch Ratings.
Subsequent to quarter end, on November 1, 2025, Canadian Natural closed the AOSP swap with Shell. Canadian Natural now owns and operates 100% of the Albian oil sands mines and associated reserves and retains a non-operated 80% interest in the Scotford Upgrader and Quest facilities.
- The transaction adds approximately 31,000 bbl/d of annual, zero decline bitumen production, providing additional cash flow and enabling more effective and efficient operations between the Horizon and Albian mines.
- The swap did not include any cash consideration, with the exception of regular closing adjustments to reflect the effective date of March 1, 2025.
- Following the close, Canadian Natural updated its 2025 capital and production guidance as follows:
  - 2025 production guidance range of 1,560 MBOE/d to 1,580 MBOE/d.
  - 2025 operating capital forecast remains unchanged at approximately $5.9 billion, following the $100 million reduction previously announced in May 2025.
    - As a result of strong operational execution and capital discipline, additional activity on a larger asset base, following opportunistic acquisitions in the year, has been executed with no incremental capital required.

(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, 2025 dated November 5, 2025 ("MD&A").

			Three Months Ended						Nine Months Ended
($ millions, except per common share amounts)			Sep 30 2025		Jun 30 2025		Sep 30 2024		Sep 30 2025		Sep 30 2024
Net earnings		$	600	$	2,459	$	2,266	$	5,517	$	4,968
Per common share	- basic	$	0.29	$	1.17	$	1.07	$	2.64	$	2.33
	- diluted	$	0.29	$	1.17	$	1.06	$	2.63	$	2.31
Adjusted net earnings from operations⁽¹⁾		$	1,801	$	1,496	$	2,071	$	5,733	$	5,437
Per common share	- basic⁽²⁾	$	0.86	$	0.71	$	0.98	$	2.74	$	2.55
	- diluted⁽²⁾	$	0.86	$	0.71	$	0.97	$	2.73	$	2.53
Cash flows from operating activities		$	3,940	$	3,114	$	3,002	$	11,338	$	9,954
Adjusted funds flow⁽¹⁾		$	3,920	$	3,262	$	3,921	$	11,712	$	10,673
Per common share	- basic⁽²⁾	$	1.88	$	1.56	$	1.85	$	5.59	$	5.01
	- diluted⁽²⁾	$	1.87	$	1.55	$	1.84	$	5.57	$	4.97
Cash flows used in investing activities		$	2,234	$	1,941	$	1,274	$	5,487	$	3,681
Net capital expenditures⁽³⁾		$	2,124	$	1,915	$	1,349	$	5,342	$	4,083
Net capital expenditures⁽³⁾, excluding net acquisition costs		$	1,318	$	1,691	$	1,261	$	4,312	$	3,996
Abandonment expenditures		$	189	$	193	$	204	$	570	$	495
Daily production, before royalties
Natural gas (MMcf/d)			2,668		2,407		2,049		2,510		2,102
Crude oil and NGLs (bbl/d)			1,175,604		1,019,149		1,021,572		1,122,859		977,265
Equivalent production (BOE/d)⁽⁴⁾			1,620,261		1,420,358		1,363,086		1,541,127		1,327,593
(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) Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2024. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. (4) 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 $0.6 billion in Q3/25 reflected a non-cash recoverability charge of approximately $0.7 billion related to an increase in the estimate for future abandonment costs for the Ninian field and T-Block assets in the North Sea. Adjusted net earnings from operations, excluding the impact of the recoverability charge and unrealized foreign exchange and risk management activities, was strong at $1.8 billion in the quarter.

RETURNS TO SHAREHOLDERS

Canadian Natural has a strong history of 25 consecutive years of growing its sustainable dividend with a CAGR of 21% 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.
- Returns to shareholders in Q3/25 were strong, totaling approximately $1.5 billion, comprised of $1.2 billion of dividends and $0.3 billion through the repurchase and cancellation of approximately 7.2 million common shares at a weighted average price of $43.12 per share.
- Year to date, up to and including November 5, 2025, the Company has returned a total of approximately $6.2 billion directly to shareholders through $4.9 billion in dividends and $1.3 billion through the repurchase and cancellation of approximately 29.6 million common shares at a weighted average price of $42.92 per share.
- Subsequent to quarter end, Canadian Natural declared a quarterly cash dividend on its common shares of $0.5875 per common share. The quarterly dividend will be payable on January 6, 2026 to shareholders of record at the close of business on December 12, 2025.

CORPORATE UPDATE

Canadian Natural is pleased to announce the appointment of Ms. Shelley A.M. Brown, CM, FCPA, FCA, ICD.D, O.C., to the Board of Directors of the Company and to the Audit Committee effective November 4, 2025. Ms. Brown is a Chartered Accountant who retired as a Senior Audit Partner with Deloitte after more than 35 years in public accounting. Ms. Brown has extensive experience working with public companies in the mining and manufacturing sectors and has over 30 years of experience working with both non-profit and public company boards including in the role of audit committee chair. Ms. Brown holds a Bachelor of Commerce from the University of Saskatchewan and is a Fellow of the Institutes of Chartered Accountants of Alberta, Saskatchewan, British Columbia and Ontario.

OPERATIONS REVIEW

North America Oil Sands Mining and Upgrading

Three Months Ended

Nine Months Ended

Sep 30
2025

Jun 30
2025

Sep 30
2024

Sep 30
2025

Sep 30
2024

Synthetic crude oil production (bbl/d) ⁽¹⁾⁽²⁾

581,136

463,808

497,656

546,635

451,298

(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 581,136 bbl/d of SCO in Q3/25, an increase of 17% from Q3/24 levels, reflecting the additional working interest in AOSP acquired in December 2024 combined with effective and efficient operations.
- Oil Sands Mining and Upgrading achieved strong upgrader utilization in Q3/25 of 104%.
- Oil Sands Mining and Upgrading operating costs are industry leading, averaging $21.29/bbl (US$15.46/bbl) of SCO in Q3/25.
Subsequent to quarter end, Canadian Natural closed the AOSP swap with Shell on November 1, 2025, with an effective date of March 1, 2025. Canadian Natural now owns and operates 100% of the Albian oil sands mines and associated reserves and retains a non-operated 80% interest in the Scotford Upgrader and Quest Carbon Capture and Storage facilities.
- The transaction adds approximately 31,000 bbl/d of annual, zero decline bitumen production, providing additional cash flow and enabling more effective and efficient operations between the Horizon and Albian mines.
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			Nine Months Ended
	Sep 30 2025	Jun 30 2025	Sep 30 2024	Sep 30 2025	Sep 30 2024
Bitumen production (bbl/d)	274,752	274,789	271,551	278,046	269,258
Net bitumen wells drilled	11	24	25	53	78
Net successful bitumen wells drilled	11	24	25	53	78
Success rate	100 %	100 %	100 %	100 %	100 %

Thermal in situ production averaged 274,752 bbl/d in Q3/25, comparable to Q3/24 levels.
- Thermal in situ operating costs remain strong, averaging $10.35/bbl (US$7.52/bbl) in Q3/25, a decrease of 2% from Q3/24 levels of $10.52/bbl.
Canadian Natural has significant thermal in situ facility processing capacity of 340,000 bbl/d, resulting in approximately 70,000 bbl/d of annual available capacity. The Company has decades of strong 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.
- At Primrose, the Company began drilling a Cyclic Steam Stimulation ("CSS") pad in Q3/25 with production targeted to come on in the second half of 2026.
- At Jackfish, the Company brought a Steam Assisted Gravity Drainage ("SAGD") pad on production in July 2025 as planned.
- At Kirby, the Company brought a five well-pair SAGD pad on production in late October 2025 as planned.
- At Pike, the Company tied the two recently drilled SAGD pads into the Jackfish facilities. These two SAGD pads are targeted to keep the Jackfish facilities at full capacity with the first pad targeted to come on production in January 2026 and the second pad targeted to come on production in Q2/26.
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 Steam to Oil Ratio ("SOR") and optimizing solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
- At the commercial scale solvent SAGD pad at Kirby North, current SOR reductions and solvent recoveries are meeting expectations following recent workovers and optimizations.
- At Primrose, the Company is continuing to operate its solvent enhanced oil recovery pilot in the steam flood area to optimize solvent efficiency and to further evaluate this commercial development opportunity.

Crude oil and NGLs - excluding Thermal In Situ Oil Sands
	Three Months Ended			Nine Months Ended
	Sep 30 2025	Jun 30 2025	Sep 30 2024	Sep 30 2025	Sep 30 2024
Crude oil and NGLs production (bbl/d)	309,873	271,022	228,221	285,931	234,537
Net crude oil wells drilled	78	57	59	192	130
Net successful crude oil wells drilled	78	57	58	191	129
Success rate	100 %	100 %	98 %	99 %	99 %

North America E&P liquids production, excluding thermal in situ, averaged 309,873 bbl/d in Q3/25, an increase of 36% or approximately 82,000 bbl/d from Q3/24 levels, reflecting opportunistic acquisitions and strong organic growth from heavy crude oil multilaterals, liquids-rich natural gas and light crude oil, partially offset by natural field declines.
- Primary heavy crude oil production averaged 87,705 bbl/d in Q3/25, an increase of 14% from Q3/24 levels, reflecting strong drilling results from the Company's multilateral wells, partially offset by natural field declines.
  - Canadian Natural's highly successful multilateral drilling program continues to unlock opportunity on our approximately 3 million net acres of high quality land throughout our primary heavy crude oil assets.
  - Operating costs in the Company's primary heavy crude oil operations averaged $16.46/bbl (US$11.95/‍bbl) in Q3/25, a decrease of 12% from Q3/24 levels, primarily as a result of higher production volumes and the increasing proportion of lower operating cost multilateral production.
- Pelican Lake production averaged 42,070 bbl/d in Q3/25 a decrease of 7% from Q3/24 levels, reflecting planned maintenance in Q3/25 and the low natural field declines from this long life low decline asset.
  - Operating costs at Pelican Lake averaged $9.00/bbl (US$6.54/bbl) in Q3/25, an increase of 3% Q3/24 levels.
- North America light crude oil and NGLs production averaged 180,098 bbl/d in Q3/25, an increase of 69% or approximately 74,000 bbl/d from Q3/24 levels, primarily reflecting production volumes from the acquisition of liquids-‍rich Duvernay assets in Q4/24, light crude oil Palliser Block assets in Q2/25 and the liquids-rich Montney assets in the Grande Prairie area in Q3/25.
  - Operating costs in the Company's North America light crude oil and NGLs operations averaged $12.91/‍bbl (US$9.38/bbl) in Q3/25, a decrease of 6% from Q3/24 levels of $13.73/bbl, primarily reflecting higher production volumes.
- As previously announced, on July 2, 2025, Canadian Natural closed an acquisition of liquids-rich Montney assets located in the Grande Prairie area for approximately $750 million, which included production of approximately 32,000 BOE/d, including 12,500 bbl/d of NGLs.

North America Natural Gas
	Three Months Ended			Nine Months Ended
	Sep 30 2025	Jun 30 2025	Sep 30 2024	Sep 30 2025	Sep 30 2024
Natural gas production (MMcf/d)	2,658	2,398	2,039	2,498	2,091
Net natural gas wells drilled	17	22	24	58	65
Net successful natural gas wells drilled	17	22	24	58	64
Success rate	100 %	100 %	100 %	100 %	98 %

North America natural gas production averaged 2,658 MMcf/d in Q3/25, an increase of 30% from Q3/24 levels, primarily reflecting opportunistic acquisitions and strong drilling results in the Company's liquids-rich natural gas assets, partially offset by natural field declines.
- North America natural gas operating costs averaged $1.14/Mcf in Q3/25, a decrease of 7% from Q3/24 levels of $1.23/Mcf, primarily reflecting higher production volumes and cost efficiencies.

International Exploration and Production

	Three Months Ended			Nine Months Ended
	Sep 30 2025	Jun 30 2025	Sep 30 2024	Sep 30 2025	Sep 30 2024
Crude oil production (bbl/d)	9,843	9,530	24,144	12,247	24,293
Natural gas production (MMcf/d)	10	9	10	12	11

International E&P crude oil production volumes averaged 9,843 bbl/d in Q3/25, a decrease of 59% compared to Q3/24 levels. The decrease reflects temporary suspension of production at Baobab in Offshore Africa due to the planned refurbishment on its floating production storage and offloading ("FPSO") vessel, both planned and unplanned maintenance and planned decommissioning activities in the North Sea and natural field declines.
- The annual production impact in 2025 from the planned Baobab FPSO refurbishment is targeted to be approximately 7,800 bbl/d, with production targeted to resume in Q2/26.

Drilling Activity	Nine Months Ended
	September 30, 2025		September 30, 2024
(number of wells)	Gross	Net	Gross	Net
Crude oil ⁽¹⁾	252	244	212	207
Natural gas	73	58	77	64
Dry	1	1	2	2
Subtotal	326	303	291	273
Stratigraphic test / service wells	516	493	460	394
Total	842	796	751	667
Success rate (excluding stratigraphic test / service wells)		99 %		99 %
(1) Includes bitumen wells.

Canadian Natural drilled a total of 303 net crude oil and natural gas wells in the first nine months of 2025, 30 more than in the first nine months of 2024.

MARKETING

		Three Months Ended									Nine Months Ended
		Sep 30 2025			Jun 30 2025			Sep 30 2024			Sep 30 2025			Sep 30 2024
Benchmark Commodity Prices
WTI benchmark price (US$/bbl) ⁽¹⁾	$	64.95		$	63.71		$	75.16		$	66.67		$	77.55
WCS heavy differential (discount) to WTI (US$/bbl) ⁽¹⁾	$	(10.36	)	$	(10.19	)	$	(13.51	)	$	(11.07	)	$	(15.46	)
WCS heavy differential as a percentage of WTI (%) ⁽¹⁾		16 %			16 %			18 %			17 %			20 %
Condensate benchmark price (US$/bbl)	$	63.12		$	63.42		$	71.24		$	65.45		$	73.71
SCO price (US$/bbl) ⁽¹⁾	$	66.26		$	64.69		$	76.51		$	66.66		$	76.42
SCO premium (discount) to WTI (US$/bbl) ⁽¹⁾	$	1.31		$	0.98		$	1.35		$	(0.01	)	$	(1.13	)
AECO benchmark price (C$/GJ)	$	0.94		$	1.97		$	0.77		$	1.61		$	1.35
Realized Prices
Exploration & Production liquids realized price (C$/bbl) ^(2)(3)(4)(5)	$	72.57		$	69.58		$	79.15		$	74.06		$	78.67
SCO realized price (C$/bbl) ^(1)(3)(4)(5)	$	87.85		$	87.22		$	100.93		$	90.45		$	99.19
Natural gas realized price (C$/Mcf) ⁽⁴⁾	$	1.49		$	2.58		$	1.25		$	2.37		$	1.80
(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.
Canadian Natural has total contracted crude oil transportation capacity of 256,500 bbl/d, with committed volumes to Canada's west coast and to the United States Gulf Coast, being approximately‍ ‌22% of 2025 forecasted liquids production. The egress supports Canadian Natural's long-term sales strategy by targeting expanded refining markets, driving stronger netbacks while also reducing exposure to egress constraints.
The North West Redwater refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 38,434 bbl/d in Q3/25, reflecting the successful completion of the planned turnaround during the quarter.
Canadian Natural has a diversified natural gas marketing strategy with the Company targeting in 2025 to use the equivalent of approximately 31% of forecasted natural gas production in its Oil Sands Mining and Upgrading and thermal operations, with approximately 38% targeted to be sold at AECO/Station 2 pricing, and approximately 31% targeted to be exported to other North American and international markets capturing higher natural gas prices, maximizing value.
Canadian Natural has entered into a long-term natural gas supply agreement with Cheniere Energy, Inc. ("Cheniere") 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, subject to a number of conditions precedent including a positive final investment decision of the Sabine Pass Liquefaction Expansion Project by Cheniere.
- 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, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, forecast and anticipated abandonment expenditures, income tax expenses, and other targets provided throughout this 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") 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 bitumen, crude oil, 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 deployment of technology and technological innovations; 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, 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, 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, natural gas and NGLs 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; 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-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; 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 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, 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, 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. 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 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, 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 Common Share Split and Comparative Figures

At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a Special Resolution approving a two for one common share split effective for shareholders of record as of market close on June 3, 2024. On June 10, 2024, shareholders of record received one additional share for every one common share held, with common shares trading on a split-adjusted basis beginning June 11, 2024. Common share, per common share, dividend, and stock option amounts for periods prior to the two for one common share split have been updated to reflect the common share split.

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. These amendments include substantial financial penalties and, effective June 20, 2025, a private right of action which permits private parties to seek an order from the Competition Tribunal under the deceptive marketing practices provisions. Uncertainty surrounding the interpretation and enforcement of this legislation 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, 2025, and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2024. 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, 2025 have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").

Production volumes and per unit statistics are presented throughout this document 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, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. 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, 2024, 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 the Company's MD&A, dated November 5, 2025.

ADVISORY

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 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 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, 2025 dated November 5, 2025.

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 management as required.

Up to October 2024, before the announcement of the Chevron acquisition, the Company was targeting to allocate 100% of its free cash flow in 2024 to shareholder returns.

In October 2024, with the announcement of the Chevron acquisition, the Board of Directors adjusted the allocation of free cash flow as follows:

60% of free cash flow to shareholder returns and 40% to the balance sheet until net debt reaches $15 billion.
When net debt is between $12 billion and $15 billion, free cash flow allocation will be 75% to shareholder returns and 25% to the balance sheet.
When net debt is at or below $12 billion, free cash flow allocation will be 100% to shareholder returns.

The Company's free cash flow for the three months ended September 30, 2025 and comparable periods is shown below:

		Three Months Ended
($ millions)		Sep 30 2025		Jun 30 2025			Sep 30 2024
Adjusted funds flow⁽¹⁾	$	3,920	$	3,262		$	3,921
Less: Dividends on common shares		1,228		1,233			1,118
Net capital expenditures⁽²⁾		2,124		1,915			1,349
Abandonment expenditures		189		193			204
Free cash flow	$	379	$	(79	)	$	1,250
(1) Refer to the descriptions and reconciliations to the most directly comparable GAAP measure, which are provided in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and nine months ended September 30, 2025 dated November 5, 2025. (2) Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2024. 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, 2025 dated November 5, 2025.

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 2025		Jun 30 2025		Dec 31 2024		Sep 30 2024
Long-term debt	$	17,268	$	17,081	$	18,819	$	10,029
Less: cash and cash equivalents		113		102		131		721
Long-term debt, net	$	17,155	$	16,979	$	18,688	$	9,308

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 is a forward-looking non-GAAP financial measure. The capital budget is based on net capital expenditures (non-GAAP financial measure) and includes acquisition capital related to a number of acquisitions for which agreements between parties have been reached as at the time of the Company's 2025 budget press release on January 9, 2025. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for more details on net capital expenditures.

The 2025 capital forecast reflects forecasted net capital expenditures, before 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 on 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 2025 Third Quarter Earnings Results on Thursday, November 6, 2025 before market open.

A conference call will be held at 9:00 a.m. MDT / 11:00 a.m. EDT on Thursday, November 6, 2025.

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: 56299#)

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
2100, 855 - 2 Street S.W. Calgary, Alberta, T2P 4J8
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

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To view the source version of this press release, please visit https://www.newsfilecorp.com/release/273369

Canadian Natural Resources Limited Announces 2025 Third Quarter Results