Given the success in conventional multilateral drilling, what is the potential for secondary recovery and waterflood in the company's portfolio?

Scott Stauth confirmed the company is actively pursuing secondary recovery. They are commencing testing of a polymer flood in the Clearwater, which looks promising, and have implemented a waterflood at Smith in the same area. “We are commencing testing of a polymer flood currently in the Clearwater. And we'll look to see how those results work out down the road here, but looks very promising. And we also looked at our Smith waterflood and have that implemented as well in that area.”

What is the company's view on the current M&A environment, comfort with policy, and opportunities to improve operations from acquired assets?

Scott Stauth highlighted that recent acquisitions were accretive, adding immediate cash flow and inventory for development. The company focuses on M&A that adds value for shareholders, balancing organic growth with opportunistic acquisitions. He did not specifically address policy comfort but emphasized the value-add of the deals. “We're not buying something just to grow. We're buying something that adds cash flow that as inventory for development programs and ultimately adds additional value for our shareholders.”

Has there been a noticeable shift in how Canada's Competition Bureau assesses acquisitions, given recent deferrals on deals?

Scott Stauth believes there hasn't been a significant difference. He characterized the Palliser Block delay as a unique circumstance due to the number of facilities and competitors in the area, and does not anticipate similar issues going forward. “No, I don't believe there's a significant difference there, Greg. The particular one that we have in the Palliser Block, it was unique to a certain extent. Just in terms of the amount of the facilities in the area, various different competitors in the area. I would call it a unique circumstance.”

CNQ

Canadian Natural (CNQ) Q2 FY25 earnings call: guidance and Q&A

Earnings call· Jun 2025 (Q2 FY25)· Energy· Aug 7, 2025

Source: earnings call transcript

Executive summary

Canadian Natural Q2 FY25 — Strong Operational Performance and Accretive Acquisitions Drive Shareholder Returns

Canadian Natural delivered robust Q2 FY25 results, driven by strong operational execution, including an early and on-budget AOSP turnaround, and the integration of accretive acquisitions. The company maintains a disciplined capital allocation strategy, prioritizing shareholder returns and balance sheet strength, while also pursuing organic growth and strategic M&A. Management anticipates continued strong performance in the second half of the year, with a focus on optimizing acquired assets and maintaining a low WTI breakeven.

Highlights

Achieved quarterly production volumes of approximately 1.420 million BOEs per day, up 135,000 BOEs per day YoY.
Successfully completed AOSP turnaround 5 days ahead of schedule and on budget.
Closed two accretive acquisitions adding approximately 82,000 BOEs per day of production and 1,000 drilling locations.
North American light crude oil and NGL production increased 31% YoY to 140,700 barrels per day.
Operating costs on light oil and NGL operations decreased 24% YoY to $10.94 per barrel.
Adjusted fund flow reached approximately $3.3 billion, and adjusted net earnings were $1.5 billion in Q2 FY25.

Concerns

Delayed closing of Palliser Block acquisition resulted in only 2,000 barrels per day added to Q2 production, versus a budgeted 50,000 BOEs per day.
Pelican Lake production decreased 4% YoY to 43,100 barrels per day due to natural field declines.
Oil Sands Mining and Upgrading costs increased 2% YoY to $26.53 per barrel of SCO, reflecting the AOSP turnaround.
AECO pricing outlook remains soft despite LNG Canada startup, with anticipated ebbs and flows in the next 5+ years.

Guidance & targets

Category	Target	Timeline	Confidence
Second half 2025 operating results	continue to deliver strong operating results medium materiality	H2 FY25	High
Full year capital budget	essentially remain unchanged high materiality	FY25	High
AOSP swap closing	targeting to close in the third quarter medium materiality	Q3 · FY25	High
2025 corporate production guidance update	plan to update after AOSP swap closes medium materiality	FY25	Medium
Multilateral well drilling	26 more wells in 2025 than originally budgeted low materiality	FY25	High
Duvernay D&C costs	improvement of approximately 16% or $2 million per well lower than compared to 2024 costs medium materiality	FY25	High
Duvernay D&C costs (further improvement)	further improvement of $200,000 per well compared to the first quarter of 2025 medium materiality	FY25	High
Duvernay 2025 budget production	approximately 60,000 barrels per day medium materiality	FY25	High
Primrose CSS pad production	targeted to come on in 2026 low materiality	FY26	High
Kirby SAGD pad production	targeting to bring on production in the fourth quarter of 2025 low materiality	Q4 · FY25	High
Pike SAGD pads production	first pad targeted to come on in Q1 2026, second pad in Q2 2026 low materiality	Q1 / Q2 · FY26	High
2025 shareholder returns	similar shareholder returns in 2025 as compared to 2024 high materiality	FY25	High
2025 free cash flow allocation to shareholder returns	allocating 60% of free cash flow in 2025 to shareholder returns high materiality	FY25	High
Dividend growth	some room for dividend growth here into 2026 medium materiality	FY26	Medium
Net debt target	$15 billion high materiality	end of 2026 · FY26	High
WCS differential	$10 to $13 medium materiality	Ongoing	Medium
SCO premium	minus 1.5 to plus 1.5 medium materiality	Ongoing	Medium
Synthetic production run rate	600,000 range medium materiality	H2 FY25	High

Segment performance

Segment	Revenue	YoY	QoQ	Margin
Primary Heavy Oil Increase reflecting strong drilling results from multilateral well program. Operating costs comparable to Q2 2024. Production: 87,300 barrels per dayOperating costs: $17.44 per barrel	—	10%	—	—
Pelican Lake Decrease reflecting low natural field declines from long-life, low-decline assets. Operating costs comparable to Q2 2024. Production: 43,100 barrels per dayOperating costs: $9.01 per barrel	—	-4%	—	—
North American Light Crude Oil and NGL Primarily driven by Duvernay assets and strong drilling results in liquids-rich natural gas assets. Operating costs decreased 24% YoY due to higher production volumes. Production: 140,700 barrels per dayOperating costs: $10.94 per barrel	—	31%	—	—
Duvernay Assets Achieving strong production results and further cost reductions. Q2 operating costs decreased more than 11% compared to Q1 2025. Operating costs: $8.43 per barrel (Q2 2025)Operating costs (Q1 2025): $9.52 per BOE	—	—	—	—
North American Natural Gas Operating costs decreased 10% YoY compared to $1.19 per Mcf in Q2 2024, primarily due to higher production volumes. Production: 2.4 Bcf per dayOperating costs: $1.07 per Mcf	—	14%	—	—
Thermal In Situ Resulting from capital-efficient thermal pad development program. Operating costs comparable to Q2 2024. Production: 274,800 barrels per dayOperating costs: $11.05 per barrel	—	3%	—	—
Oil Sands Mining and Upgrading Increase due to reliability enhancement project, Scotford Upgrader debottleneck (both completed 2024), and additional 20% working interest in AOSP (acquired Dec 2024). Operating costs increased 2% YoY reflecting AOSP turnaround in Q2 2025. Production (SCO): 463,800 barrels per dayOperating costs: $26.53 per barrel of SCO	—	13%	—	—

CNQ operating KPIs by quarter

CNQ operating KPIs stated on its earnings calls, by fiscal quarter
KPI	This call Jun 2025 Q2 FY25	Sep 2025 Q3 FY25	Change vs prior quarter
Production	~1.42M boe/d In the second quarter of 2025, despite the planned turnaround at AOSP, which reduced production levels in the quarter by approximately 120,000 barrels per day, we achieved quarterly production volumes totaling approximately 1.420 million BOEs per day, including liquids production of 1.019 million barrels per day and natural gas production of 2.4 Bcf per day. Source: earnings call transcript	~1.62M boe/d Our production totaled approximately 1.62 million BOEs per day, which, as mentioned, includes records for both liquids and natural gas at approximately 1.18 million barrels per day and approximately 2.7 Bcf per day, respectively. Source: earnings call transcript	—
Oil production Pelican Lake	~43.1K bbl/d Pelican Lake production averaged approximately 43,100 barrels per day in the second quarter, a decrease of 4% from the second quarter of 2024, reflecting low natural field declines from this long life, low decline assets. Source: earnings call transcript	~42.1K bbl/d Pelican Lake production averaged approximately 42,100 barrels per day, a decrease of 7% from Q3 of '24, reflecting planned maintenance that took place in Q3 of '25 and the low nature of field declines from this long-life, low-decline asset. Source: earnings call transcript	—
Oil production Thermal In Situ	~274.8K bbl/d In our Thermal In Situ operations, we achieved strong thermal production in the second quarter, averaging approximately 274,800 barrels per day. Source: earnings call transcript	274.752K bbl/d In our thermal in situ operations, we achieved strong thermal production in the quarter, averaging 274,752 barrels per day in Q3, up slightly from Q3 2024 levels. Source: earnings call transcript	—
Oil production Oil Sands Mining and Upgrading	~463.8K bbl/d In our Oil Sands Mining and Upgrading, during the second quarter of 2025, our world-class oil sands mining and upgrading production averaged approximately 463,800 barrels per day of SCO, an increase of 13% from the second quarter of 2024. Source: earnings call transcript	581.136K bbl/d During the quarter, our world-class oil sands mining and upgrading production was strong, averaging 581,136 barrels per day of SCO, an increase of approximately 83,500 barrels per day or 17% from Q3 2024 levels, reflecting the additional interest in the AOSP acquired in December 2024, combined with our effective and efficient operations, which drove stronger utilization of approximately 104% in the quarter. Source: earnings call transcript	—

Operating figures the company stated on at least two of the calls shown, checked against each call's transcript. Click a figure to read the sentence. A dash means it was not stated that quarter.

Deals & partnerships

Palliser Block seller Acquisition of oil and NGL production and high-quality land.

Originally budgeted to close March 1, 2025. Included 1.1 million net acres of high-quality land with approximately 850 light crude oil inventory locations.

Grand Prairie area seller Acquisition of liquids-rich Montney assets. $750 million

Assets directly adjacent to existing Montney assets, providing synergy opportunities. Added approximately 120,000 net acres of high-quality land with approximately 150 liquids-rich inventory locations.

Shell (implied) AOSP swap to acquire 31,000 barrels a day of bitumen production.

The swap involves Canadian Natural acquiring 31,000 barrels a day of bitumen production. Expected to close in Q3. Will allow for easier movement of equipment, people, and optimization between AOSP and Horizon.

AOSP partner (implied) Acquisition of additional working interest in AOSP.

Acquired an additional 20% working interest in AOSP.

Capital programs

AOSP Turnaround completed

Successfully completed 5 days ahead of schedule and on budget in Q2 2025. Reduced production levels by approximately 120,000 barrels per day in the quarter.

Duvernay Drilling and Completion Cost Improvement underway

Benefit:16% or $2 million per well lower than 2024 costs

Driven by extended well lengths (20% longer than 2024) and optimized completion designs. Further improvement of $200,000 per well compared to Q1 2025.

Primrose CSS Pad Development underway

Start: Q3 FY25

Benefit:production targeted to come on in 2026

Turned to drill a CSS pad in Q3 2025.

Jackfish SAGD Pad Development completed

Benefit:production brought on in July 2025

Recently drilled SAGD pad brought on production in July.

Kirby SAGD Pad Development underway

Benefit:production targeted to come on in Q4 2025

Targeting to bring a recently drilled 5-well SAGD pad on production.

Pike SAGD Pads Development underway

Benefit:keep Jackfish plants at full capacity

Completed drilling 2 SAGD pads, which will be tied into existing Jackfish facilities.

Kirby North Commercial Scale Solvent SAGD Pad underway

Start: June 2024 (solvent injection)

Began solvent injection in June 2024. Executed workovers on 2 well pairs in Q2 2025 to enhance SOR's solvent recovery.

Horizon Reliability Enhancement Project completed

Benefit:eliminating the need for a turnaround at Horizon in 2025

Completed in 2024, contributing to increased Oil Sands Mining and Upgrading production.

Scotford Upgrader Debottleneck completed

Completed in 2024, contributing to increased Oil Sands Mining and Upgrading production.

Risks & headwinds

Delayed acquisition closing Q2 FY25

Palliser Block acquisition delayed from March 1 to June 26, 2025, resulting in only 2,000 bbl/d added to Q2 production vs. budgeted 50,000 BOEs/day.

Mitigation:Company successfully closed the deal and integrated the assets, maintaining full-year capital budget unchanged (excluding purchase price).

Soft AECO pricing Next 5+ years

Forward strip pricing for AECO looks soft, with anticipated ebbs and flows in pricing over the next 5+ years.

Mitigation:Company's diversified asset base and low-cost structure provide resilience. Expects a period of time to fill full 2 Bcf capacity of LNG Canada once second train is online.

WCS differential volatility Ongoing

WCS differential anticipated to vary in the range of $10 to $13, with potential for wider or narrower periods.

Mitigation:Acknowledges structural change post-TMX, but notes impacts from OPEC production and refinery turnaround timing. Company is prepared for variability.

SCO premium volatility Ongoing

SCO premium relative to WTI expected to vary in a range of minus 1.5 to plus 1.5.

Mitigation:Anticipates ebbs and flows related to turnaround activities and distillate strength. No structural shifts expected.

Haul road conditions impact on production H2 FY25

Solid haul road conditions in winter are not typically seen in summer and fall, potentially impacting operational efficiency.

Mitigation:Despite this, the company expects a synthetic production run rate in the 600,000 bbl/d range for the second half of the year.

What to watch in Q3 FY25

AOSP swap closing

Q3 FY25

Current Targeting to close in Q3 FY25

Target Closed

Why it matters

The closing of the AOSP swap will bring 100% ownership of the mine, enabling significant synergies with Horizon and potentially impacting future production optimization.

We are also targeting to close the AOSP swap in the third quarter and we plan to update our annual 2025 corporate production guidance after that swap closes.

Find out whether CNQ delivers this. Inve re-checks your case every morning.

Q&A highlights

How is the company approaching the heavier debt maturity year in 2027, considering tight credit spreads and sticky long-term rates?

Victor Darel stated that with strong cash flow generation forecast for 2025 and 2026, refinancing needs might be lower than anticipated. The company will assess refinancing requirements in 2026 and aim to pick an opportune time.

“When we look at our balance sheet now coming out of 2025 and forecast into 2026, cash flow generation in the period looks strong. So I think our refinancing needs will probably be a little bit lower than what you might be anticipating.”

asked by Patrick O'Rourke · answered by Victor Darel

2 min read 5 chapters

Detailed narrative

Operational Excellence and Turnaround Success

Canadian Natural demonstrated strong operational performance, highlighted by the successful completion of a planned turnaround at AOSP 5 days ahead of schedule and on budget. This efficiency, combined with reliability enhancements and debottlenecking projects at Horizon and AOSP, led to high production and upgrader utilization.

In July 2025, Oil Sands Mining and Upgrading production averaged approximately 602,000 barrels per day with upgrader utilization of 106%, setting a strong pace for the second half of the year.

Accretive Acquisitions and Inventory Growth

The company closed two significant acquisitions: the Palliser Block in June and liquids-rich Montney assets in July. The Palliser Block, though delayed, added 2,000 bbl/d to Q2 production and 850 light crude oil drilling locations. The Montney acquisition, for approximately $750 million, added 32,000 BOEs per day (including 12,500 bbl/d NGLs) and 150 liquids-rich drilling locations.

These acquisitions collectively added 82,000 BOEs per day of production and roughly 1,000 drilling locations, immediately contributing to cash flow and bolstering inventory.

Conventional and Thermal E&P Performance

Conventional E&P assets showed strong results, with primary heavy oil production up 10% YoY to 87,300 bbl/d, driven by multilateral well programs. North American light crude oil and NGL production increased 31% YoY to 140,700 bbl/d, benefiting from Duvernay assets and drilling efficiencies.

Duvernay operating costs decreased over 11% QoQ to $8.43 per barrel, with D&C costs targeting a 16% improvement. Thermal In Situ production averaged 274,800 bbl/d, up 3% YoY, supported by capital-efficient pad development programs at Primrose, Jackfish, and Kirby.

Financial Strength and Shareholder Returns

Canadian Natural reported adjusted fund flow of $3.3 billion and adjusted net earnings of $1.5 billion for Q2 FY25. The company returned $1.6 billion to shareholders in the quarter ($1.2 billion dividends, $400 million buybacks), bringing year-to-date returns to $4.6 billion.

Net debt remained below $17 billion, with a debt-to-EBITDA ratio of 0.9x and liquidity over $4.8 billion. The company targets similar shareholder returns in 2025 as in 2024, allocating 60% of free cash flow to returns, compared to 100% in 2024.

Strategic Asset Base and Future Outlook

The company emphasized its strategically balanced asset base, comprising long-life, low-decline assets that provide a competitive advantage through commodity cycles. The upcoming AOSP swap, expected to close in Q3, will bring 100% ownership of the mine, enabling further synergies with Horizon.

Management anticipates the WCS differential to range between $10-$13 and the SCO premium between -$1.5 to +$1.5, with an expected synthetic production run rate around 600,000 bbl/d for the second half of 2025.

Summary of the company's earnings call; see how call summaries are prepared. Not investment advice.