Canadian Natural Resources Limited (NYSE:CNQ) Q4 2024 Earnings Call Transcript

Canadian Natural Resources Limited (NYSE:CNQ) Q4 2024 Earnings Call Transcript March 6, 2025

Canadian Natural Resources Limited misses on earnings expectations. Reported EPS is $0.66 EPS, expectations were $0.69.

Operator: Good morning. We would like to welcome everyone to Canadian Natural’s 2024 Fourth Quarter and Year-End 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, March 6, 2025 at 9 a.m. 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, and good morning, everyone. Thank you, this morning, for joining Canadian Natural’s 2024 fourth quarter and year-end earnings conference call. As always, before we begin, I’d like to remind you of our forward-looking statements, and it should be noted that in our reporting disclosures, everything in Canadian dollars, unless otherwise stated, and we report our reserves and production before royalties. Also, I would suggest that you review our advisory section in our financial statements that includes comments on non-GAAP disclosures. Speaking on today’s call will be Scott Stauth, our President, Robin Zabek, our Chief Operating Officer of E&P, and Mark Stainthorpe, our Chief Financial Officer. Additionally, in the room with us this morning is Jay Froch, CEO of Oil Sands, and Victor Darel, Senior Vice President of Finance and Principal Accounting Officer.

Scott will first provide some examples of our top-tier performance and strong execution over recent years before getting into the numerous operational records achieved in 2024. Next, Robin will provide highlights of our growing, high-value reserves that compete on a global scale. Mark will then summarize our financial results that includes robust adjusted funds flow, earnings, and returns to shareholders. To close, Scott will summarize prior to opening up the call for questions. With that, over to you, Scott.

Scott Stauth: Thank you, Lance, and good morning, everyone. Before I get into our 2024 results, I’d like to run through some key factors that highlight our top-tier performance over the past three years in execution, effective and efficient operations, returns to shareholders, resource value growth, and opportunistic acquisitions. Our unique and diverse asset base provides us with a competitive advantage as we have ample organic growth opportunities and can allocate capital to the highest return projects without being reliant on any one commodity. Our strong culture of continuous improvement is about doing it right, and it is driven by teams in the organization that believe ownership and accountability deliver consistently strong results.

All employees are shareholders, and we firmly see the value in having our employees as owners, and importantly, we’ve been able to keep the team together, which is important for our long-term sustainability and business continuity. Over the past three years, we have achieved the following successes. Absolute production growth of approximately 82,100 BOEs per day, the vast majority of which was liquids growth. We have delivered annual production per share CAGR of 7%. We improved liquids margins significantly by reducing operating costs by more than $3 per barrel, or 15%, equating to an incremental margin of approximately $1.2 billion based on 2024 production. We returned over $11 per share to shareholders through dividends and share repurchases.

We increased our annualized quarterly dividend by 59% to $2.25 per share from $1.42 per share, and the board has subsequently increased the dividend by another 4%. Our share count reduced by approximately 234,000 shares, or 11% inclusive of shares issued upon exercise of stock options. Adding more value at AOSP through the acquisition that closed in Q4 of 2024, and a swap transaction targeted to close by the end of Q2 this year, consolidating our working interest in the Albion Mines to 100%. In the Albion Mines, these transactions will add approximately 93,500 barrels per day of long-life, zero-decline production to our world-class oil sands mining and upgrading assets. Additionally, we acquired Chevron’s 70% operator working interest of the light crude oil and liquid rich assets in the Duvernay.

These assets are targeted to average approximately 60,000 BOEs per day in 2025, and provide the opportunity for meaningful near-term growth while contributing additional free cash flow. Expanding even further on AOSP and going back to 2017, we unlocked significant long-term value since we first acquired an interest in this world-class asset. We’ve increased production and reduced operating costs through process improvements and optimization projects that improved reliability and increased utilization. Since 2017, we’ve increased growth production at Albion Mines by 30%, or over 70,000 barrels per day. Upgraded capacity was also increased to match the increased production from the mines. We’ve decreased AOSP per unit operating costs by more than 30%, or approximately $10 per barrel.

This equates to an incremental margin of approximately $800 million based on 2024 production. With 100% working interest in the mines, once the swap transaction closes, we are targeted to unlock further value with our effective and efficient operations and relentless continuous improvement culture. Adding even more value to our world-class oil sands mining and upgrading assets, when you combine that increased ownership interest with the recently completed debottlenecking and reliability projects, our total oil sands mining production capacity increases to approximately 592,000 barrels per day. And further to that, when you combine our top-tier conventional crude oil and liquid rich natural gas assets with our leading oil sands mining and upgrading assets, you get a significant and sustainable free cash flow and the ability to organically grow production if it makes sense to do so.

I will now run through our strong 2024 operational results and highlights. We hit several new records across our assets in 2024, including record annual total production of approximately 1.36 million BOEs per day, including record liquids production of over 1 million barrels per day. Record annual oil sands mining and upgrading production of 472,245 barrels per day, and record quarterly production of 534,631 barrels per day. These record production rates resulted in higher upgrader utilization of 99% in 2024, including planned turnarounds and 105% utilization in the fourth quarter. Our oil sands mining and upgraded operating costs are industry-leading, averaging $22.88 per barrel in 2024 and $20.97 per barrel in the fourth quarter. Our oil sands mining and upgrading assets continue to achieve strong production and high utilization in January 2025 and February 2025, averaging on a gross basis approximately 634,000 barrels per day over the two months.

February 2025 was the highest monthly gross production in our history at approximately 640,000 barrels per day as we focus on continuous improvement initiatives combined with the strong performance from the reliability enhancement project at Horizon and the de-bottleneck project at Scotford. Additionally, further value has been unlocked from piping modifications completed during the recent de-bottleneck project at Scotford Upgrader. These modifications unlock approximately 5,000 barrels per day of annual gross production from the Albion mines, resulting in higher utilization during planned upgraded turnarounds. This increased zero decline production will continue to benefit Canadian Natural’s for decades, including our increased ownership in the Albion mines.

In our thermal in-situ operations, we’ve achieved record production in 2024, averaging just over 271,000 barrels per day, a 3% increase over 2023, which was driven by our capital-efficient thermal pad development program. 2024 thermal in-situ operating costs were strong, averaging 1104 per barrel, which is down 16% compared to 2023, primarily reflecting lower energy costs and higher production volumes. We have significant available processing capacity of approximately 70,000 barrels per day in our thermal operations. We continue to utilize this available capacity through our strong execution on our drill-to-fill pad additions and have been able to bring these pads on production ahead of schedule. For example, at Wolf Lake, we brought a SAGD pad on production ahead of schedule in Q4 of 2024, which was originally targeted for Q1 of 2025.

At Primrose, we brought a CSS pad on production ahead of schedule in Q4 of 2024, originally targeted for Q2 of 2025. A second CSS pad has been drilled and is targeted to come on production ahead of schedule in late Q1 of 2025, originally budgeted for the second quarter of 2025. At Jackfish, we drilled a SAGD pad in Q4 of 2024, with production targeted to come on in Q3 of 2025. At Pike, we are drilling two SAGD pads in the first half of 2025, which will be tied into the 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 are currently drilling a SAGD pad targeted to come on production in Q4 of 2025, with a second SAGD pad targeted to be drilled in Q4 of 2025 and come on production in Q4 of 2026.

On the conventional side of the business, primary heavy oil production averaged approximately 79,100 barrels per day, a 2% increase over 2023, reflecting strong results from multilateral wells on our extensive heavy oil land base. We drilled 121 net horizontal multilateral primary heavy oil wells in 2024, compared to 104 in 2023. Multilateral wells combine increased reservoir capture and higher production with reduced servicing requirements, which lowers operating costs. As we shift more of our primary heavy oil assets to multilateral development, we are seeing overall operating costs coming down as these wells are more efficient and require less servicing activity. In 2024, primary heavy oil operating costs averaged $18.11 per barrel, down 9% from 2023.

We continue to optimize well design and length in our highly successful multilateral program, achieving top-tier average initial peak rates of approximately 250 barrels per day per well, which is 43% higher than the budgeted initial peak rate of 175 barrels per day per well, and a further 9% higher than our previously disclosed rate of 230 barrels per day. North American light crude oil and NGL production averaged approximately 114,400 barrels per day in 2024, an increase of 5% compared to 2023. Half of this increase is driven by strong organic growth and liquid-rich natural gas, with the remainder related to recently acquired Duvernay assets. We achieved a 17% reduction in operating costs on light crude oil and NGLs, averaging $13.55 per barrel in 2024, compared to 2023.

North American natural gas production averaged 2.14 BCF in 2024, which is comparable to 2023. In 2024, we remained focused on liquid-rich natural gas activity in the Montney and Deep Basin, while certain dry natural gas activity in 2024 was deferred due to lower natural gas prices. Operating costs in our North American natural gas averaged $1.19 per MCF in 2024, which is 6% lower than 2023. Complementing the opportunistic acquisitions completed in 2024, as well as those announced but not yet closed in 2025, we have plenty of organic growth opportunities within our large, diverse asset base. We will leverage this expanded portfolio of organic growth opportunities to continue creating long-term shareholder value into the future while maintaining the flexibility to manage the pace of these development opportunities to deliver strong returns.

We have a long track record of consistently delivering strong, industry-leading results driven by our safe, reliable operations and relentless focus on continuous improvement which maximizes long-term shareholder value. Now I will turn it over to Robin to speak to our 2024 year-end reserves.

Robin Zabek: Thank you, Scott, and good morning, everyone. I’ll start by pointing out that as in previous years, 100% of Canadian Natural’s reserves are externally evaluated and reviewed by independent, qualified reserve evaluators. Our 2024 reserves disclosure is presented in accordance with Canadian reporting requirements, using forecast prices and escalated costs, on a company working interest before royalties basis. As you just heard from Scott, Canadian Natural had a very strong year, but one of the many places in which that is evident are the company’s reserves. For December 31, 2024, total proved reserves are 15.2 billion BOE, and total proved plus probable reserves are 20.1 billion BOE. This is a 9% increase in both proved and proved plus probable reserves compared to December 2023.

Canadian Natural replaced 2024 production by 365% on a total proved basis and 422% on a total proved plus probable basis. The accretive acquisition of Chevron’s Alberta assets in December 2024 added material reserves and NPV growth. And as you heard from Scott, these assets will continue to drive value for decades. It is also notable that even excluding the contribution of acquisitions in 2024, the company’s organic reserves replacement would still have been about 118% of production in total proved and about 128% of production in total proved plus probable. Highlighting one of the key attributes that differentiate Canadian Natural’s assets, approximately 74% of total proved reserves are from long-life, low-decline or zero-decline assets. Resulting in a total proved reserve life index of 33 years and a total proved plus probable reserve life index of 44 years.

Notably, at year-end 2024, approximately 50% of the company’s total proved reserves are high-value SEO with zero decline and a total proved reserve life index of 43 years. In 2024, the strength of Canadian Natural’s assets and results also continue to be reflected in our strong finding and development costs. The corporate finding, development and acquisition costs, excluding changes in future development costs, are $7.82 per BOE for total proved reserves and $6.76 per BOE for total proved plus probable reserves. Including changes in future development costs, corporate FD&A is $13.56 per BOE for total proved and $12.60 per BOE for total proved plus probable. The net present value of future net revenue before income tax, using a 10% discount rate and including the full company ARO, is approximately $170 billion for total proved reserves and approximately $206 billion for total proved plus probable reserves.

This equates to net asset values of $74.83 per share for total proved and $91.72 per share for total proved plus probable. In summary, our 2024 reserves reflect the strength and depth of Canadian Natural’s asset base, the predictability of the company’s long-life, low-decline reserves, the value of accretive acquisitions completed in 2024, and our proven ability to deliver organic reserves and value growth. I will hand over to Mark now for financial highlights.

Mark Stainthorpe: Thanks, Robin and good morning everyone. In 2024, we delivered strong financial results on the back of the solid operational performance Scott discussed, which are highlighted by annual adjusted funds flow of $14.9 billion, including Q4 ’24 adjusted funds flow of $4.2 billion. Our capital program for 2024 was approximately $100 million under budget of $5.3 billion, resulting in significant free cash flow in the year, where we returned approximately $7.1 billion to shareholders in 2024, inclusive of our sustainable and growing dividend and share repurchases. We increased our quarterly dividend twice in 2024, and subsequent to year-end, 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 to $0.5875 per common share or $2.35 per common share annualized, with 2025 being the 25th consecutive year of dividend increases by Canadian Natural, with a compound annual growth rate of 21% over that time.

After the recent acquisitions, our financial position remains strong, and with the additional free cash flow generation, our U.S. dollar WTI break-even remains top-tier in the low-to-mid 40 WTI per barrel, with strong balance sheet metrics, including debt-to-EBITDA at 1.1x and debt-to-book capital at 32% at the end of 2024. Liquidity remains strong, and including undrawn revolving bank facilities and cash, liquidity at the end of the quarter was approximately $4.7 billion. Our industry-leading cost structure, predictable long-life, low-decline assets and reserve base, combined with a relentless commitment to continuous improvement, continues to drive significant value at Canadian Natural. This is all a result of our focused and dedicated teams across our business who are aligned with shareholders and have the drive to do things right every day.

This is a unique competitive advantage and facilitates driving strong, long-term returns on capital. With that, I’ll turn it back to you, Scott, for some final comments.

Scott Stauth: Thank you, Mark. In summary, our consistent and reliable results are underpinned by safe and reliable operations. Our commitment to continuous improvement is driven by a strong team culture in all areas of our company, the focus on improving our cost, strong execution of organic growth opportunities, and increasing value to shareholders. We consistently deliver top-tier operational and financial results, which is unique and sustainable, clearly demonstrating our ability to both economically grow and deliver returns to our shareholders by balancing across our four pillars of capital allocation. I’d like to take this opportunity to thank Mark for all of his service as our CFO and contributions to the Management Committee. I’d also like to congratulate Victor in his new role, new position as our CFO. And with that, I will turn it over for questions.

Q&A Session

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

Greg Pardy: Thanks for the rundown. And indeed, Mark, congrats on your new role. It’s been great to work with you. You’ll probably get more sleep now on weekends. And welcome, Victor. A couple of questions on my end. And I guess, Scott, you talked about, the Shell swap and then the Chevron deal and so forth. What do those two transactions mean on a combined basis for your shareholder returns, but also conceivably organic growth at AOSP down the road?

Scott Stauth: Thanks, Greg. So, yes, those two acquisitions, I talked about adding 93,000 barrels a day of production through those acquisitions. And obviously that will be a significant contribution to our overall free cash flow, which will formulate itself into our shareholder payment programs proportionally. So there’s significant value. Those are high dollar value barrels as well. If you look at organic growth opportunities, Greg, I would point out that there is already existing approvals in place for Jack Pine mine expansion in the order of 100,000 barrels a day. And I’d also point out that we have license capacity availability in the existing JPM and MRM licenses as well. So we have the opportunity for good, strong growth opportunities in the Albion mines.

And I think it’ll take lots of work on egress opportunities in order to ensure that those barrels can move to market. But there’s certainly the opportunities there and very well laid out in terms of the reserve life that we can get out of that project with no decline. So there’s a lot of overall value wrapped up in that.

Greg Pardy: Okay. Thanks. Thanks for that. And maybe I’ll just switch gears. I mean, in your opening remarks, you talked about a number of the thermal developments where you’re ahead of schedule. So is this intentional? Is there something kind of bigger going on with a series of projects you’re laying out?

Scott Stauth: Yes. I think, Greg, what’s happened over time and folks shouldn’t be overly surprised at times when we do, when we’re able to exceed our expectations, when we sanction a project to get it on production, such as these SAGD and CSS pads. And that’s because we employ our continuous improvement. So every time we build a pad, we take the learnings from that and things that we could do better and we apply it to the next pad. So, arguably we’re getting caught up on some of that here, but certainly it’s nothing ordinary from what we normally do. It’s just part of continuous improvement.

Operator: Thank you. The next question comes from Dennis Fong at CIBC. Please go ahead.

Dennis Fong: And again, I would like to echo the congratulations to Mark on your new role. My first question maybe follows along the line of Greg’s questions there just around your oil kind of mining operations. So, I mean, you guys have shown obviously a track record of really optimizing production and kind of throwing in a little kind of small, we’ll call it de-bottlenecking or just even driving better kind of throughput, frankly, since you started owning this asset and operating it as well. Eventually in a situation where, say, you are able to optimize the assets in such a way that exceeds Scotford Upgrader capacity, what are maybe some of your options that you can look at doing and what are the synergies in that like nearby asset structure that you can maybe lean on to kind of gain incremental margin?

Scott Stauth: Yes. Good question, Dennis. In terms of the AOSP mines and relative to the Scotford production, the next step to get higher volumes would most likely involve something similar to what we’ve talked about before over at Horizon, which is a paraffinic froth treatment opportunity. So that’s where you would get bitumen barrels. You would move to market, call it around the Scotford Upgrader. But obviously, number one, ensure the upgrader is full and kept full at all times. And secondly, it’d be providing a expansion opportunity to bring on additional bitumen barrels and move those to market.

Dennis Fong: Great. Appreciate that incremental color. And then maybe shifting gears towards the thermal side. In your press release, you’ve talked about 70,000 barrels of potential oil processing unused capacity, which really helped that drill to fill program. Can you talk towards what you’d look to be able to, or what you would need to do to further unlock that 70,000 potential barrels a day of the oil processing side? Presumably it’s about liberating steam capacity and then using that a little bit more efficiency, theoretically, I presume through Wolf Lake and Primrose.

Scott Stauth: Yes. I think you got it bang on, Dennis. It’s primarily in the Primrose Wolf Lake area. The SAGD assets are primarily full, certainly Jackfish is. And so, yes, I think if you just, over time, with steam capacity availability, we’ll continue to do our pad adds. And we’re also working and continue to work on the implementation of solvents in those areas. And so I think I talked about this on the last call, Dennis, that primarily we’ll be looking to do pad ad opportunities in Primrose probably before we would do the solvent injection. But they certainly go hand in hand, and the teams are working on both those opportunities. But to get to your point, the steam availability is the key factor there, but we would plan on having pad ads to ensure we’re maximizing our capacity available from our steam plants.

Operator: Thank you. The next question comes from Manav Gupta at UBS Financial. Please go ahead.

Manav Gupta: You guys have a very informed view of the markets out there, and I’m just trying to understand how we’re thinking about the eco prices next 18 to 24 months given some of the LNG projects which are expected to ramp up over in Canada.

Scott Stauth: Yes, it’s a good question. I think you see an uptick on the pricing going into 2026, obviously on the back of getting LNG Canada online. And I think that those opportunities will continue to allow us to move gas out of the basin here. Our focus is going to primarily be on liquids rich, gassy areas such as the Monterey and Duvernay. But it certainly looks like to me that the market is somewhat, I would say, conservative potentially on the pricing. But, again, some of that’s going to depend on how quickly that LNG capacity can be backfilled. But I think those are some of the driving factors there.

Manav Gupta: And a quick comment I also wanted. Over the last week, I think Enbridge talked about increasing mainline capacity by about, like, 150,000 barrels in the near term. And over a longer term, I think they allocated $2 billion in capital. So they’re looking to increase it to, like, 300,000 barrels. So I’m just trying to understand, in your view, is this incremental capacity needed? Would you think the basin will fill up at some point, if you could comment around that?

Scott Stauth: Well, it’s a good question. And I would say, yes, over the long term, it will. Primarily, I’d suggest that the growth opportunities, or at least the most significant growth opportunities, you would look towards the oil sands to make the biggest contributions. We’re certainly well positioned from that in our mining operations. We’ve talked about Horizon in the past, and we’re also talking about the AOSP mines as well, in terms of production growth opportunities here. So we have additional capacity in our thermal operations. So other operators do have additional opportunities as well. So I think all combined, that capacity will be utilized in the long term.

Operator: Thank you. The next question comes from Patrick O’Rourke at ATB Capital Markets. Please go ahead.

Patrick O’Rourke: Congratulations to Mark on the new role as well. I guess just from the perspective of the capital structure here with the net debt, where it is the $15 billion and $12 billion targets, just wondering about your thoughts in terms of flexing the balance sheet here in the M&A markets or acquisition market, if we do continue to see some volatility on the commodities versus the impetus to get to those enhanced shareholder returns right now.

Scott Stauth: Yes, good question, Patrick. I think that we’re quite happy with our assets. And in terms of M&A activity, we’ll just see how things unfold and the fluctuations in pricing as a result of all the discussions on tariffs and so forth. It’s going to take some time to sort some of that out. But we’re quite happy. If you look at our reserve base, we have ample opportunity to grow organically. We’ve always liked acquisitions that bring that additional value and accretive to the company. So as in the past, for the past 35 years, that’s been one of our strengths of organic growth and taking advantage of opportunities to get acquisitions. And unless there’s something that changes significantly in the environment going forward, I don’t see our strategy changing.

Patrick O’Rourke: Okay, great. And then maybe just on the operational side, looking through some of the numbers here, particularly the commercial solvent project at Kirby North, I noticed that the solvent recoveries came down very slightly in the quarter from 85% to 80%. Just wondering, how we, or how you anticipate this to trend through time. Is there any seasonality there? And then, what the view is in terms of potential proliferation of this technology now through the rest of the portfolio, now that you’ve had it online for a while.

Scott Stauth: Yes, Patrick, I don’t think I’d read anything too much into the change in terms of the recovery. It has to do with some of the nuances just with certain wells on stream or certain wells off stream for servicing or enhancements that they’re working on individual wells with. So the trajectory is what we’d anticipated in terms of the recoveries and the SOR reductions. We’d expect to see, get towards what we would think would be a solid stable state in and around July of August of this year. And then once we’ve reached that state, we’ll be able to certainly have access to all the information, all the data that’s been gathered over the past year and just determine exactly how we want to move forward from here. Now, I will say that in parallel, our teams are looking at expanding the opportunity further into areas such as Pike as we move forward.

Those opportunities would be a few years down the road say into 27 and 28 where we would look at doing the next implementation of a project such as that. But we are seeing good positive results. We’d like the opportunity to be able to bring reserves forward. And there’s lots of reserves that we have intersect the operations. So it provides a significant opportunity to bring those reserves forward based on our capital allocation program. So it’s another good tool in our toolbox.

Operator: Thank you. The next question comes from Menno Hulshof at TD Securities. Please go ahead.

Menno Hulshof: Thanks and good morning, everyone. Can we begin by maybe having you elaborate on the pipeline modification that allowed you to add 5,000 barrels per day of capacity at Albion? Like what exactly got done there? What was the capital efficiency? And then higher level, what other near-term debottlenecking opportunities are you seeing at the AOSP or Horizon that you’re prepared to flag today? Thank you.

Scott Stauth: Yes, good question. Quite simply, the work that they’ve done there is just looking at de-bottlenecking some of the piping that allowed the transfer between the two different upgraders there. There was pumps that the teams had increased the sizing on, just modification to certain sizes of piping. So really it was just about ensuring that the teams had the flows well understood, the engineering part of it understood, not overly complex, but still stepped through it very methodically, making sure that we were making the right moves there. I don’t have a capital efficiency number for you off the top of my head, but the key to this is they’re low capital dollars overall. And if you look at it, that’s 5,000 barrels a day for 50 years.

Additional opportunities, we’ll continue to work on efficiencies and finding tweaks that we can do or create capacity in both the Horizon and the Albion assets. You saw we had very strong production in the first quarter, started to ramp up strongly in the fourth quarter as well. And I think what you’re seeing that is a result of all the good work that our teams have done on implementing the reliability project enhancement and the debottleneck project at Scotford. The teams did very good work on that, and the results of the work that they did on those projects are turning out to be better than we actually anticipated. So we’re getting strong run rates, and we’re getting more production through the facility than we originally had the engineering design for.

So that’s a very good positive from a go-forward basis here.

Menno Hulshof: Terrific. And then my second question is on the North Sea. We’ve seen a pretty big shift in focus back to energy security in the UK and Europe more generally, and I think there’s certainly a growing view that European domestic supply growth becomes a much bigger priority looking forward. You have a very long history in the North Sea. I think everybody understands that. It’s a basin with an unconstrained market egress? And so my question is, is there any scenario where you would consider building up your position again, or is the most likely scenario still a slow wind down of those assets?

Scott Stauth: Yes, it’s a good question. I think in what we know today and where we’re at with the development of the reserves there, we would continue to unwind and abandon the facilities. That development in the North Sea has the downward direction, and the production is not something new, as you know. There’s been significant, I would say, political regime to move away from oil and gas, and to your point, that that’s probably going to change. I think for our operations in the North Sea, it’s probably those decisions were made several years ago. Potentially had the fiscal regime been different five, ten years ago, it might be different for us today. But as we stand today, we’re not likely to invest capital in those areas.

Operator: Thank you. The next question comes from Roger Read at Wells Fargo. Please go ahead.

Roger Read: Yes, thanks. Good morning. A lot of talk on here about, incremental investments growth, both things you’ve done and things you may do. I’m just curious how you look at, from either a return standpoint, or what your break-evens are as you think about these investments. And, you know, where you’ve been able to debottleneck, obviously it’s going to be a very low break-even. But if you were doing something more, actually putting another hole in the ground and looking to produce, how does that compare as you look across the various ops?

Scott Stauth: So, Roger, you’re referring to, like, a larger project. Is that what you mean by your commentary?

Roger Read: No, I would actually keep it within the things you’ve discussed so far. So not trying to go, you know, do something significant, but for the smaller things you’ve been doing, you know, how should we think about that from, call it a $60, $65 oil world, however, you want to define that, what it’s really delivering in terms of bottom-line impacts.

Scott Stauth: Okay. I got you. So really those types of projects, like the ones we’ve done in the past, where we get these incremental barrels on a year-over-year basis, those are the first projects that you want to look at doing because they’re going to have the best capital efficiencies, and you already have the infrastructure essentially in place. So you don’t change anything from an operating cost perspective. In terms of adding costs, it actually helps your operating costs because most of your costs there are already on a fixed basis, Roger. So all these areas where we’re, especially in the mines, where we’re adding incremental barrels or, in fact, any area in the company where we’re adding incremental barrels through facilities, they’re great projects with the best returns because the infrastructure is mostly built.

Roger Read: Yes, well, I guess I was just curious. I mean, how do you look at them from a — I’m just trying to think about what makes sense here in terms of investment in a, you know, call it a flattish oil outlet. It seems like you’ve got these opportunities. I mean, are they the equivalent to $30 break-evens or $40 or $50? I mean, just how do you kind of scale that up?

Scott Stauth: Yes. They would make sense at low-dollar breakeven, like low-dollar costs, Roger. I think I follow what you’re getting at. But, again, because they have some of the best capital efficiencies, you would always want to do those first, Roger.

Roger Read: All right, I’ll leave it there. Thanks.

Scott Stauth: Basically any investment environment.

Operator: Thank you. The next question comes from John Moyle at JPMorgan. Please go ahead.

John Moyle: So my first one is on the mines, and I think you addressed this a little bit. But they ran a very strong rate in January, February, in the context of your now-raised capacity. There’s no turnaround at Horizon this year. You do have one at AOSP and 2Q. But outside of the scope of turnarounds and, of course, excluding the impact of the close of the swap, can these types of levels be sustained or is there anything seasonal or more kind of non-repeatable in those early results?

Scott Stauth: Yes, they’re not seasonal. And I think you just have to look at it. These two months, very strong rates. The rates increased from the fourth quarter coming into the first quarter, and that is because we’ve optimized the projects that I talked about at both Scotford and Horizon. So those are definitely strong rates. There was essentially no unplanned downtime to speak of in the past two months. We normally do budget for unplanned downtime on any given month throughout the entire year. So I would expect that, while on the one hand, our teams are going to focus on ensuring they’re optimizing the production opportunities as much as they possibly can, we still understand that from time to time there could be some unplanned downtime due to an unforeseen event that’s budgeted.

And so, that’s likely to happen. The good news is I think I look at it as a positive. The rates are stronger than we would have anticipated. So even with unplanned downtime going forward, we’re still going to see some very strong rates coming out of both those mines.

John Moyle: Great, thank you. And then my next question is on the Chevron acquisition. With that deal now closed, do you have a better sense or maybe a better sense that you’re willing to share of the cash that’s available from tax pools? And is there a good way for us to think about how that could impact your cash taxes in 2025?

Mark Stainthorpe: Hi, it’s Mark. We don’t guide to sort of tax pools particularly on that. I know I’ve discussed it before when you look at the PP&E values of the acquisition. We do generate, tax pools. And you saw that in Q4 where we’re able to claim a full year of tax depreciation in that one quarter. So that’ll be a go for it, but you’ll see it over the full year. So that’s just the difference, and that’s the impact of the taxes you see in Q4.

Operator: Thank you. The next question comes from Neil Mehta at Goldman Sachs. Please go ahead.

Neil Mehta: So my first question is just on the macro. Obviously, there’s a lot of moving pieces around tariffs, around WCS. In the 25 presentation, you guys talked about using a $14 planning assumption for WTI WCS, which I guess was the strip at the time. And has anything changed in that worldview? How are you thinking about the impacts of tariffs to the extent that there is some durability to them? And any perspectives on how much is absorbed by the producer versus the refiner? So just a lot of moving pieces around the differential, but your perspective on the market would be great.

Scott Stauth: Yes, good question, Neil. I think what you’re seeing in the market today, we’ve seen WCS to Houston change over the past month here in and around at $4 range. It’s narrowed into around $2 to $3, so call it $2.50. It suggests that maybe some of the cost of the tariffs would be passed on through to the consumer in the U.S. On the WCS Hardisty, WTI WCS at Hardisty side, we’ve seen fluctuations. I saw this morning, April, in and around some sales at $12.50. Over the last couple of days, they’re up or upwards of $14.50. So there’s some fluctuation in Hardisty on that. So still very fluid in terms of how this is all going to work out. It is our view that certainly the U.S. consumer is going to end up having to absorb the cost of the tariffs.

To what degree, we’re not exactly sure how the market’s going to play out. It could be on a shared basis. It could be leaning more towards the U.S. consumer paying more for it than the producer would. We’ll see how that all balances out. But certainly in our view, we believe it’s going to be not all placed back on the producer.

Neil Mehta: That’s helpful. The offset to that could be currency, right? Because the CAD is now out to $1.44 or so. Just love your perspective on how that can provide an offset. As you think about, in general, which ending you are in terms of driving your operating costs per barrel lower, how much more is there to go as we work our way through the year?

Scott Stauth: Another good question. I think we’ll see where the dollar goes. It’s difficult to make a comment at this time. There’s a lot of political activity driving that. I’ll probably just not comment on that. Sorry, the second part of your question was? Can you repeat that?

Neil Mehta: It was just on OpEx per barrel. How much can you drive that lower with and without currency?

Scott Stauth: I think that one thing you need to remember about Canadian Natural is we already have a very low cost structure. It’s one of the key differentiators relative to our peers. We’ve got a low break-even, low operating costs, low maintenance capital, and significant capital flexibility in our 2025 budget. I think that bodes very well. Then you look at it and say, okay, half of our production essentially is SCO production. It’s taking pricing plus or minus WTI. There’s another strength for Canadian Natural. If you look at how our barrels are marketed, most of our barrels are marketed here in Canada with the exception of 87,500 barrels a day that we carry down Flanagan and Keystone. Then, of course, the $169,000 barrels per day that we move to the West Coast, which is basically isolated from the tariff.

Most of our barrels are pretty much sold here in Alberta as well. Yes, our barrels are dependent on WCF pricing, certainly, but the underlying or the underpinning factor for Canadian Natural is our low cost structure. I just want to make sure that that message is well understood. We get superior netbacks, and that low cost structure has helped us through previous times such as COVID. We were able to work with our vendors when oil pricing dipped right down into the low single digits. Certainly, the cost of services dropped at that time. We were able to work with our vendors for a short period of time to work through that. We came out of that very strong. Again, it’s on the back of the fact that we have a low cost and very sustainable operating cost platform across all of our assets, both on the natural gas side and especially on the oil sands mining side.

Operator: Thank you. The next question comes from [Eric Busslinger at UBR] [ph]. Please go ahead.

Unidentified Analyst: Great quarter and results into this first part of the year. Just following up on the Jack Pine potential expansion, 100,000 barrels a day. One, what’s the limiting factor in sanctioning that tomorrow? Two, is that included in your base reserves for 2024?

Scott Stauth: In terms of the decision to go ahead with something like that, the great thing about us is we have ample opportunity for organic growth. The challenging thing in Canada is getting approval for large projects. The Jack Pine mine expansion already has that approval in place, so we could build that out over time here in our capital allocation model. I think it’s a great tool to have in our tool chest here. When we do the project, if and when we do the project, we’ll talk more about that over time, but certainly we’re in an advantageous position here to be able to do a project of magnitude of that size. All depends on our outlook for pricing, for egress, for carbon capture. There’s a number of factors that are going to go into making that decision. As you know, you build 100,000 or 150,000 barrels a day project in the mine, and it’s going to run for 40 to 50 years.

Operator: Thank you. We have no further questions. I will turn the call back over to management for closing comments.

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

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