Operator: Good morning. We would like to welcome everyone to Canadian Naturals 2025 First Quarter Earnings Conference call and webcast. After the presentation, we will conduct a question-and-answer session. Instructions will be given at that time. Please note that this call is being recorded today, May 8, 2025 at 7 AM Mountain Time. I would now like to turn the meeting over to your host for today’s call, Lance Casson, Manager of Investor Relations. Please go ahead.

Lance Casson: Thank you, operator. Good morning, everyone. Thank you for joining Canadian Naturals 2025 first quarter earnings conference call. As always, I would like to remind you of our forward-looking statements, and it should be noted that in our reporting disclosures, everything is in Canadian dollars, unless otherwise stated, and we report our reserves and production before royalties. Also, I would suggest you review the advisory section in our financial statements that include comments on non-GAAP disclosures. Speaking of today’s call, we have Scott Stauth, our President, and Victor Darel, our Chief Financial Officer. Additionally, in the room with us this morning is Robin Zabek, COO of E&P, Jay Froc, COO of Oil Sands, and Mark Stainthorpe, Executive Advisor.

Scott will first provide details of our top-tier operational performance and effective and efficient operations that are driving strong results. Victor will then summarize our financial results, including strong financial position and returns to shareholders. To close, Scott will summarize prior to opening up the line for questions. With that, over to you, Scott.

Scott Stauth: Thank you, Lance, and good morning, everyone. We have a long track record of being a safe, industry-leading, effective, and efficient producer while constantly delivering top-tier operational and financial performance. All our employees, our shareholders, focused on doing it right while driving strong results and always working on continuous improvement opportunities. We achieved record quarterly production during the first quarter of 2025 of approximately 1.582 million BOEs per day, which included a record quarterly liquids production of approximately 1.174 million barrels per day, 79% of which was long-life, low-decline production, and record quarterly natural gas production of 2.451 BCF per day. During the first quarter, our world-class oil sands mining and upgrading asset achieved record quarterly SCO production of approximately 595,000 barrels per day of SCO.

This was an increase of 34% or approximately 150,000 barrels per day compared to the first quarter of 2024. Gross production of approximately 630,000 barrels per day in the first quarter of 2025 with upgrade utilization of 106% was the highest quarterly oil sands mining and upgrading gross production in the company’s history. This was achieved through successes in the recently completed Reliability Enhancement Project and Scotford Upgrader Debottle Network, which drove the strong performance. These achievements were anchored by industry-leading SCO operating costs of $21.88 per barrel, which drove significant free cash flow in the quarter. Importantly, when comparing to peers in 2024, our annual oil sands mining and upgrading operating costs were in the range of $7 to $10 per barrel lower than our peer average.

This equates to an incremental annual margin of approximately $1.2 billion to $1.7 billion based on our 2024 annual production. Our record natural gas production in the quarter includes the recently acquired Duvernay assets that closed in December of 2024. We are achieving strong production results and cost reductions on these assets. We are confident we will add even more value than what we planned at the time of the acquisition. This is made possible through our commitment to continuous improvement and a strong team culture that focuses on improving our already top-tier operating costs, driving execution of organic growth opportunities, and maximizing value for our shareholders. Additionally, as a result of good work by our team’s funding efficiencies, we are reducing our 2025 capital budget by $100 million and are now forecasting capital for 2025 at $6.05 billion excluding abandonments.

Importantly, this reduction will have no impact on our planned activities or targeted production volumes for 2025. I will now run through the remaining first quarter operational results. On the conventional side of the business, primary heavy oil production averaged approximately 85,600 barrels per day for the first quarter, an increase of 9% over the first quarter of 2024, reflecting strong drilling results from our multilateral well program which offset natural field declines. Primary heavy oil operating costs averaged $18.13 per barrel, which is down 5% from the first quarter of 2024, primarily reflecting higher production and lower energy costs. Pelican Lake production averaged just over 43,000 barrels per day in the first quarter of 2025, a decrease of 4% from the first quarter of 2024, reflecting low natural gas declines for this long life low decline asset.

Operating cost at Pelican averaged $9.77 per barrel in the first quarter, which is comparable to the last year. North American Light Crude Oil and NGL production averaged approximately 147,800 barrels per day in the first quarter, which is up 30% from the first quarter of 2024, primarily driven by our recently acquired Duvernay assets and strong drilling results in our liquid rich natural gas assets. Operating costs from our Light Crude Oil and NGL operations averaged $13.15 per barrel, a decrease of 14% compared to the first quarter of 2024, reflecting higher production and lower costs. Our recently acquired Duvernay assets, our effective and efficient operations, various synergies and expertise in similar plays such as the Montney have resulted in both capital and operating cost efficiencies.

Additionally, we are on track to achieve 2025 budget production of approximately 60,000 barrels per day. By optimizing well length and completion designs in the Duvernay combined with a top tier execution, we are drilling longer wells with improved reservoir access at lower costs. On a length normalized basis, combined drilling and completions costs for 2025 are targeting an improvement of approximately 14%, or $1.8 million per well compared to 2024. We are targeting to drill 43 gross wells in the Duvernay as part of the 2025 Capital Development Program. Additionally, operating costs in the Duvernay during the first quarter of 2025 are strong, averaging approximately $9.52 per BOE. North American natural gas production for the first quarter was a record, averaging more than 2.45 BCF per day, an increase of 14% over the first quarter of 2024.

Operating costs on North American natural gas averaged $1.16 per MCF, which is down 9% compared to the first quarter of 2024, primarily resulting from higher production volumes. In our thermal in situ operations, we achieved strong thermal production in the first quarter, averaging approximately 284,700 barrels per day. This is up 6%, approximately 16,500 barrels per day from the first quarter of 2024, resulting from a capital efficient thermal pad ad development program. First quarter thermal in situ operating costs averaged $11.23 per barrel, which is down 20% compared to the first quarter of 2024, primarily reflecting higher production volumes and lower energy costs. At Primrose, following strong results from the recently drilled CSS pad, we are planning to reallocate a portion of pad ad capital in 2025 to Primrose from Kirby to maximize returns.

We now target to drill a CSS pad in the fourth quarter of this year with production targeted to come on in 2026. At Jackfish, we finished drilling a SAGD pad in the fourth quarter of 2024 with production targeted to come on in the third quarter of this year. At Pike, we completed drilling one SAGD pad and we are currently drilling a second SAGD pad, both of which will be tied into existing Jackfish facilities. These two pads are targeted to come on production in 2026 and keep the Jackfish plants at full capacity. At Kirby, we recently finished drilling a SAGD pad, which is targeted to come on production in the fourth quarter of this year. At our commercial scale solvent SAGD pad at Kirby North, we began solvent injection in June of 2024 and solvent recovery continues to meet expectations exceeding 80%.

As we continue to build off the successes, we identified several workover opportunities targeting enhancing injections, liner and steam solvent distribution, SORs, and production. These workovers are targeted to be completed in the second quarter and we will continue monitoring over the second half of 2025. Canadian Natural’s advantage is our ability to effectively allocate cash flow to our four pillars. We have a well-balanced, diverse, and large asset base, of which a significant portion is long-life, low-decline assets requiring less capital to maintain our volumes. We will continue to allocate cash flow to our four pillars in a disciplined manner to maximize value for our shareholders, which is all driven by effective capital allocation, effective and efficient operations, and by our team who deliver top-tier results.

Now, I will turn it over to Victor for our first quarter financial review.

Victor Darel: Thanks, Scott, and good morning everyone. In the first quarter of 2025, we delivered excellent financial results on the strong operational performance that Scott just discussed, and this is highlighted by adjusted fund flow in the quarter of approximately $4.5 billion and adjusted net earnings of $2.4 billion. Returns to shareholders in the quarter were $1.7 billion, including $1.2 billion of dividends and an additional $500 million of share repurchases, which continue to increase shareholder value on a per-share basis. Free cash flow in the quarter contributed to a reduction in net debt by approximately $1.4 billion, and further strengthening our balance sheet metrics, where debt-to-EBITDA was at one time and debt-to-book capital came in at 30% at quarter end.

Liquidity remained strong, and including undrawn revolving bank facilities and cash, liquidity at the end of the quarter was approximately $5.1 billion. We increased our quarterly dividend twice in 2024 and subsequently in March of 2025. Given our strong financial position and significant and sustainable free cash flow generation, our Board of Directors approved a further 4% increase to our quarterly dividend, a $58.75 per common share, or $2.35 per common share annualized, marking 2025 as the 25th consecutive year of dividend increases by Canadian Natural, with a compound annual growth rate of 21% over that time. Thus, at subsequent to quarter end, the Board has approved a quarterly dividend of $58.75 per common share, payable on July 3, 2025 to shareholders of record at the close of business on June 13, 2025.

Our industry-leading cost structure, predictable, long-life, low decline assets and reserve base, combined with a consistent commitment to continuous improvement, continues to drive significant value at Canadian Natural. This all contributes to our top-tier U.S. dollar WTI break-even that remains in the low-to-mid $40 WTI U.S. range, which we define as the WTI price required to generate the adjusted fund flow to cover maintenance capital and dividends. Our focused and dedicated teams across our business are aligned with shareholders and have the drive to do things right every day. This is part of Canadian Natural’s unique competitive advantage and facilitates driving strong, long-term returns on capital. Those are my comments, Scott, and that I’ll turn it back to you.

Scott Stauth: Thanks, Victor. In summary, we continued our focus on safe, reliable operations and enhancing our top-tier operations. We are in very strong position with our low-cost structure, a decades-long track record of solid execution, and we are nimble, which enhances our ability to create value for our shareholders. And with that, I will turn it over to questions.

Operator: Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] Your first question comes from Greg Pardy, RBC Capital Markets.

Greg Pardy: Thanks. Good morning. Scott, I was maybe hoping to start with you. I mean, you have no autonomous haul trucks at Horizon AOSP, and your OpEx is kind of crazy low. And if I look at your performance in the first quarter, it is very strong despite the cold snaps. The question is, can humans outperform autonomous haul, especially in the extreme conditions we saw in the first quarter?

Scott Stauth: Thanks, Greg. I think the way to look at it, first off, I cannot really comment on the impact of cold weather to autonomous, but what I can say is historically that the longer the duration of the extreme cold weather, the more challenging things can become over time. But really, I cannot comment on the autonomous part of it. I just know that our teams are focused on a lot of work through the weather issues, but it’s really just a matter of the duration and the length of the cold snap.

Greg Pardy: Okay. Okay. Thanks for that. And then maybe just switching over to the financial side, maybe with Victor. I’m curious as to whether you’re prioritizing net debt reduction as we go through the first half and what we should sort of think about in terms of shareholder returns. Do you expect perhaps more of a balance as we go between the buybacks and debt reduction, or are you really trying to get after the debt now?

Victor Darel: Yeah. Thanks, Greg. A very good question. Definitely seeing that strong operational performance here in the quarter contributing to cash flow generation and a really meaningful reduction in net debt overall. Back to the free cash flow allocation policy, though, to your point, at the current allocation of 60% to share buyback and 40% to the balance sheet, we look at that on a forward-looking annual basis. And so we’re taking a balanced approach here over the course of the coming year. And so I think you’ll see that continue over the next 12 months, just as we try to manage within the program overall. So I think you’ll see a really strong program here in 2025, and you saw that in April and May as well when you look at the results this morning.

Greg Pardy: Okay. Thanks very much.

Operator: Next question is from Manav Gupta of UBS Financial. Please go ahead.

Manav Gupta: Good morning, guys. We know your track record on acquired assets. We all saw what you did with Jackfish. And I’m just wondering here, now that you’ve acquired these additional assets from Chevron, are they meeting your expectations? And where could we see upside synergies from these assets? And also, if you could help me understand, when can we expect the Shell swap to close? Because I think that would raise your volume guidance for the year. So if you could talk through those things. Thank you.

Scott Stauth: Yeah. Thanks, Manav. So first off on the swap, I think you could expect that by the end of the second quarter here. That’s what we’re anticipating. In terms of the acquisitions on the Duvernay assets, they are meeting our expectations, continue to work the assets, reviewing all the costs, looking for every opportunity that we can to become more effective and more efficient. And with that, obviously, optimizing the production. So they are meeting our expectations.

Manav Gupta: Perfect. My quick follow-up here is a number of peers are actually lowering their capital because of lower commodity price. It looks that the $100 million reduction you did had nothing to do with the commodity price. It was just you getting a lot more efficient. So if you could confirm that. And then how are these efficiencies realized in your system, which allowed you to lower the CapEx? And is there scope for more such reductions in outer years in 2026 and 2027? Thank you.

Victor Darel: Yeah, good question, Manav. And your assumption is correct. Not so much related to pricing, just more related to the continuous improvement efforts that our teams put into looking at ways to optimize and reduce the cost. And so an example of that would be if you looked at the Duvernay, we commented about the reduced cost at 14%. So we’re seeing lower drilling cost per meter, we’re seeing lower completions cost. And then across the board, part of other components that made up the $100 million, roughly about 60 of that is in the conventional E&P and about 40 of it in the thermal and mining. We’re seeing lower costs on our facility build-out, our new well completion build-outs across the board, including in thermal.

And then in oil transfer mining, it’s made up of multiple sustaining capital components where the teams have gone back, reviewed the cost, looked at ways to optimize, finding opportunities to shave off costs through efficiencies, and that’s where the $100 million comes from.

Manav Gupta: Thank you so much. And congrats again on a strong quarter. The bar is always high for you guys, but somehow you managed to beat it every time. So congratulations.

Victor Darel: Thank you.

Operator: Thank you very much. Next question is from Dennis Fong of CIBC Capital Markets. Please go ahead.

Dennis Fong: Hi, good morning. And thanks for taking my question. The first one is a focus just around oil sands mining. I know, as you just highlighted, you’re close to completing the swap between your mining exposure versus the upgrader. I was hoping you could talk towards the opportunities that exist from owning a 100% of mining capacity in such close capacity, obviously, between Horizon and Albion. And are there ways to further integrate those operations, whether it be through kind of shared services or even an interconnection between the two facilities?

Scott Stauth: Potentially all of those, Dennis. Very good question. I think if you looked at it, the fact that we would have 100% across both sites allows us the opportunities to better utilize our equipment at various times in the year. If we have to transport some trucks from one site to another, we can do that very efficiently and very quickly. We’ll take advantage of those opportunities. And it isn’t just limited to heavy equipment. It also includes our inventory, warehouse inventory, being at the same percentages, much quicker, much more efficient and effective to be able to utilize equipment parts at both sites and services at both sites. So it ranges from small parts, Dennis, to cranes, to trucks. Those are the types of opportunities that they’re in abundance in small amounts, but it adds up to significant amount for us in terms of overall efficiencies and being able to be more effective and more efficient. So that’s where we’re at.

Dennis Fong: Great. Really appreciate that incremental color. Shifting towards Wolf Lake Primrose, you highlighted in the press release some available capacity within your thermal in-situ business. I believe this might be referring a little bit to the latent oil handling capacity of Wolf Lake Primrose and understanding that you are drilling an incremental CSS well pad there later this year. Can you talk towards or at least characterize the opportunity of backfilling that oil handling capacity or the capacity in those facilities and how you think about the potential march to kind of I think it’s 130-odd thousand barrel a day capacity that fits in Wolf Lake Primrose, which is a little bit more underutilized today.

Scott Stauth: Yeah. So good question, Dennis. And one of the reasons that we moved pad from Kirby, moved capital from Kirby to Primrose this year with good results we saw from the latest CSS pad at Primrose. We continue to see those strong results coming out of the North Primrose area. We’ll continue to make these repeatable and maximize the opportunity that we have for the related capacity both on the oil side and on the steam side. Certainly, our objective will be to ensure that the steam plants are running at 100% capacity on a year-over-year basis. And so, we will adjust our development plan according to that availability, Dennis.

Dennis Fong: Great. Thanks. Really appreciate the call. And I’ll turn it back.

Operator: Thank you. The next one who has a question will be Menno Hulshoff of TD Securities. Please go ahead.

Menno Hulshoff: Good morning, everyone. And thanks for taking my question. I just have one, maybe a quick follow-up on Manav’s question on the Duvernay. Would you be willing to elaborate on what’s getting done differently relative to Chevron? And with the understanding that it’s early days for CNQ in the play, if we were to assume that strip prices are correct, how do you think the Duvernay is going to compete for capital with the Montney on a full cycle returns basis?

Scott Stauth: The latter part of your question first, Menno. It will be very competitive with the high liquids content Montney. And in terms of the opportunities there, I can mention that we are seeing reduced drilling costs per meter. We’ve optimized the completions in terms of tonnages and looking at those kinds of efficiencies, Menno. So without getting too much more in specifics, we’re just really focused on ensuring, as we would in any asset that we’re maximizing efficiencies of the capital expenditures to ensure that we’re getting the best returns in all of those areas. So I don’t think I would look at the Duvernay as anything different than any other acquisition that we’ve ever done or our internal organic growth that we’ve done. We’re always looking for opportunities for efficiencies.

Menno Hulshoff: Thanks, Scott. I’ll turn it back.

Operator: Thank you. [Operator Instructions] Next question will come from John Moyle of JP Morgan. Please go ahead.

John Moyle: Hi, good morning. Thanks for taking my question. So my first question is on break-evens. You’ve talked about the mid-40s break-even for the company as a whole. But how should we think about it for conventional production and what price could we see a slowing of activity on the conventional side? And I guess along those lines, building on Manav’s CapEx question, what’s the flex we should think about in the CapEx budget in a lower price environment?

Victor Darel: I think, John, to lay the question first, every week we monitor our cash flows at our management committee to stay on top. And if we have to make any changes to our capital program, we can usually make that pretty quickly. And that’s sort of been the history of the company for decades. So nothing really different there. And sorry, what was the first part of your question?

John Moyle: Just the break-evens. At what price could you see some activity slowing on conventional?

Victor Darel: Yeah, we speak holistically on our break-even costs. And really, I think what everybody should just be concerned about is the fact that we are working to ensure that we’re maximizing the returns in all of our areas on all of the assets that we’re working on. We’re not just focused on one part of the business. Our business at Canadian Natural involves our thermal oil sands, mining oil sands, and the conventional operations, which is significant in terms of heavy oil, Montney, and Duvernay. So really a holistic approach, but the focus of our organization and all the staff working at Canadian Natural is to ensure that each and every one of those areas is maximized in return. In the lowest possible price environments, we will make adjustments as necessary in any one of those areas.

John Moyle: Great. Thank you very much. And then my follow-up is just on Horizon with your first year skipping the turnaround. Part one is you mentioned some maintenance work that can be done this year with zero production impact. Can you just give us a sense for what some of that is? And then secondly, when you get to the turnaround in 2026, does the scope of the turnaround change? Is it different than what a turnaround would look like in a one-year cadence?

Scott Stauth: Yeah. Good question. So the opportunity that exists for a non-production loss maintenance activity is really in the back end of the upgrader, so the secondary upgrading where you’re introducing the hydrogen for hydrotreating. We have multiple units that we use to make the SCO and secondary hydrotreating. So gas-fueled hydrotreaters, for example, distilled hydrotreaters, we can take one of those offline without having to impact the production. So that’s how it works for us, and that’s how this whole design was coming out of our reliability enhancement project. It was all part of the plan. If you look forward to 2026, I would say that in terms of the duration of the turnaround, the duration is within the same range as it would have been in previous years in the 30-35-day range for turnaround, so no significant changes there. And yeah, that’s the plan.

John Moyle: Thank you very much.

Scott Stauth: You bet.

Operator: Thank you. The next question will come from Neil Mehta of Goldman Sachs. Please go ahead.

Neil Mehta: Good morning, team. Really good netbacks this quarter relative to TI pricing, and I would think that would sequentially improve in terms of – given where the differentials are in terms of your capture relative to WTI. So just talk about the tightness of the WCS market right now, how you’re thinking about relative to WTI, how you’re thinking about that through the calendar of the year, through the rest of the calendar year. Is that a function of turnaround, or is that there’s something more structural there, just your perspective on local pricing versus WTI?

Scott Stauth: Yeah, good question. I think it can happen both based on turnaround activity that might happen on the downstream side of it. The differentials that you’re seeing sort of forecasted over the next few quarters in terms of the strip, I think our estimate would be that those are probably directionally where things will continue to go. Crude is still blowing. Obviously, the WTI has come off significantly. The differentials have tightened in, but not as significantly as much as the WTI pricing has come down, and that’s probably a function of crude oil movements and continuous flows. So our expectation would be that the differentials are in the range that they are now, and the forward months seem to be realistic to us.

Neil Mehta: Thank you. And just to follow up, how are you thinking about the recent Chevron acquisition? How has that asset performed relative to expectations? Where are the opportunities to continue to drive value?

Scott Stauth: Yeah, good question. I did answer part of that a little bit earlier, but just to reiterate, we are seeing opportunities to gain some efficiencies. We talked about a 14% reduction in our capital costs over last year. Again, the assets are meeting our expectations, and just like any acquisition, we will continue to look for any and every opportunity that there is to become more effective and more efficient.

Operator: Thank you. Next question is from Patrick O’Rourke of ATB Capital Markets. Please go ahead.

Patrick O’Rourke: Hey, good morning, guys, and thank you for taking my question. First question, just sort of with respect to carbon emissions mitigation strategies, it’s been a little bit quiet on the pathways front over the last several quarters here. We now have a bit of finality in terms of the federal government and some of the policies that they’ve had out there in their platform. Just wondering when we can expect to hear a little bit of news or sort of an update in terms of the advancement of that particular project?

Scott Stauth: Good question, Patrick, and we’re looking forward to being able to get back to the table with both levels of government to have those types of discussions. I think it’s fair to say that both federally and provincially, there’s a number of items that each one of them have on their agenda for the opportunities that they’re looking at to move forward post the election and working together. We’re hoping that in the near future, we’re going to be able to get back to the table to have some discussions and continue on with this. Don’t have a time frame for you right now, Patrick, but we’re going to be working towards that as quickly as we can get everyone together.

Patrick O’Rourke: Okay, great. Then just on Kirby here. I think for the second quarter in a row, you’ve noted in excess of 80% solvent recovery there. Just wondering if we’ve sort of hit steady state in terms of the recoveries and the asset performance and if things are generally in line with your expectations or how you’re seeing that.

Scott Stauth: Yeah, not at steady state yet, Patrick. We’re going to continue to monitor things. I did mention in the opening that we’re looking at doing a few workovers. The summary of it is that we have a number of wells that are performing at expectations in terms of recoveries, oil production, and SORs. We have other wells where we need to perform some mechanical intervention to just ensure that we have the consistent distribution and conformance across the wellbores. Nothing really that abnormal there. We’ve seen this in other types of operations in thermal as well, but it’s just a matter of optimizing the opportunity there and looking at certain wells that need a little bit of intervention to meet the expectations that we’re looking for.

Overall, we still view the opportunity for solvent injection as very positive. We’re really watching closely to ensure that we gather the right level of data. We know that we can move the solvent injection to other pads at Kirby and eventually up at Pike. We want to make sure that we get it right and we’ve got the right amount of information so that we can maximize the capital requirements as we move forward on to future pads here.

Patrick O’Rourke: Okay, thank you very much. Really appreciate the color there.

Operator: Thank you very much. There are no further questions from our phone lines. I would now like to turn the call back over to Lance Casson. Please go ahead.

Lance Casson: Thank you, operator, and thank you to everyone for joining our call this morning. If you have any questions, please give us a call. Thanks. Have a great day.

Operator: Ladies and gentlemen, this concludes our conference call for today. We thank you for participating and we ask that you disconnect your lines.

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Q1 2025

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