Canadian Natural Resources Limited (NYSE:CNQ) Q2 2025 Earnings Call Transcript

Canadian Natural Resources Limited (NYSE:CNQ) Q2 2025 Earnings Call Transcript August 9, 2025

Operator: Good morning. We would like to welcome everyone to the Canadian Natural’s 2025 Second Quarter Earnings Conference Call and Webcast. [Operator Instructions] Please note this call is being recorded today, August 7, 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.

Lance J. Casson: Good morning, everyone, and thank you for joining Canadian Natural’s 2025 Second Quarter Earnings Conference Call. As always, I’d like to remind you of our forward-looking statements. And it should be noted that in our reporting disclosure, everything is in Canadian dollars unless otherwise stated, and we report our reserves and production before royalties. Also, I would suggest to 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; and Victor Darel, our Chief Financial Officer. Additionally, in the room with us this morning is Robin Zabek, CEO of E&P; and Jay Froc, COO of Oil Sands. Scott will start off by providing details on how strong operational performance, the completion of turnarounds and our recent accretive acquisition set Canadian Natural up for a strong second half of the year.

Victor will then summarize our financial results, liquidity and our significant return to shareholders year-to-date. To close, Scott will summarize prior to open up the line for questions. With that, over to you, Scott.

Scott G. Stauth: Thank you, Lance, and good morning, everyone. Our relentless focus on continuous improvement, combined with effective and efficient operations drove strong performance year-to-date in 2025. Our ability to effectively allocate capital across our strong asset base provides us with a competitive advantage. This ability, combined with accretive acquisitions create significant long-term value for our shareholders. Our culture of accountability and the strength of our assets is a unique advantage that results in both capital and operating cost savings and maximizes value for our shareholders. We successfully completed a planned turnaround at AOSP in the second quarter of 2025, 5 days ahead of schedule and on budget.

Production and upgraded utilization at Horizon and AOSP before and after the turnaround was high, driven by strong performance from our reliability enhancement and debottlenecking projects. In July 2025, Oil Sands Mining and Upgrading production averaged approximately 602,000 barrels per day with upgrader utilization of 106%, and we expect the second half of 2025 to continue to deliver strong operating results. 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.

Total corporate production on a BOE basis in the second quarter of 2025 was up approximately 135,000 BOEs per day from the second quarter of 2024, reflecting opportunistic acquisitions and organic growth across our asset base achieved in the last 12 months. On the acquisition front, we closed the Palliser Block on June 26. Originally, we budgeted to close this acquisition on March 1, 2025, which would have added production of approximately 50,000 BOEs per day, including 20,000 barrels per day of Mannville light crude oil and NGLs in the second quarter of 2025. This acquisition and production were included in our original 2025 capital budget and production guidance. But due to the delayed closing in late June, it added only 2,000 barrels per day to our production levels for the second quarter.

This acquisition also included approximately 1.1 million net acres of high-quality land with currently identified significant light crude oil inventory of approximately 850 locations. Subsequent to quarter end, on July 2, we closed an acquisition of liquids-rich Montney assets located in the Grand Prairie area for approximately $750 million with production from the acquisition of approximately 32,000 BOEs per day, including 12,500 barrels per day of NGLs. Our original 2025 capital budget and production guidance did not include this acquisition. These assets are directly adjacent to our existing Montney assets, providing opportunities for synergies while adding approximately 120,000 net acres of high- quality land with currently identified significant liquids-rich inventory of approximately 150 locations.

To summarize, our combined recently closed accretive acquisitions have added approximately 82,000 BOEs per day of production, which includes approximately 32,500 barrels per day of liquids and total inventory of roughly 1,000 light oil and liquids-rich drilling locations. Further related to these acquisitions, our full year capital budget will essentially remain unchanged from guidance provided in the first quarter, excluding the purchase price of the Grand Prairie acquisition, which closed on July 2. All maintenance capital related to the Grand Prairie asset and other acquisitions we’ve noted will be covered by our 2025 budget. In Q1, Canadian Natural was one of the first in the industry to reduce 2025 capital spending due to efficiencies, and we are now executing development on the Grand Prairie asset, while maintaining our capital guidance we provided in the first quarter for the year.

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. I will now run through the second quarter operational results. On the conventional side of the business, primary heavy oil production averaged approximately 87,300 barrels per day in the second quarter, an increase of 10% over the second quarter of 2024, reflecting strong drilling results from our multilateral well program. We continue to achieve strong results from our drilling programs across our conventional E&P assets as we are realizing capital efficiencies, resulting in high levels of activity without increasing capital. This includes our multilateral heavy oil program, where we are targeting to drill 26 more wells in 2025 than originally budgeted.

Importantly, the low operating costs on these multilateral wells drive strong results on capital, adding significant value. Heavy oil operating costs averaged $17.44 per barrel in the second quarter of 2025, comparable with the second quarter of 2024. 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. Operating costs at Pelican Lake averaged $9.01 per barrel in the quarter comparable to the second quarter of last year. North American light crude oil and NGL production averaged approximately 140,700 barrels per day in the second quarter, which is up 31% from the second quarter of 2024, primarily driven by production from our Duvernay assets in addition to strong deal drilling results and our liquids-rich natural gas assets.

Operating costs on our light oil and NGL operations averaged $10.94 per barrel, a decrease of 24% compared to the second quarter of 2024 level of $13.75 per barrel, reflecting higher production volumes. On our Duvernay assets, we are continuing to achieve strong production results and further cost reductions on these assets in the short time that we’ve owned them. Through our culture of continuous improvement, we remain confident we will continue to realize more value for shareholders than what was originally planned at the time of the acquisition. Our team’s efforts have resulted in strong operating costs during the first 6 months of these operating these assets, averaging $8.43 per barrel in the second quarter of 2025. The decrease of more than 11% compared to the first quarter of 2025 when operating costs were $9.52 per BOE.

This results in annual operating cost savings of approximately $60 million as compared to our original target of $40 million. Our extended well lengths in the Duvernay, which are on average 20% longer than our 2024 well lengths and optimized completion designs combined with strong execution, continue to lower development costs. On a length normalized basis, combined drilling and completion costs for 2025 are now targeting an improvement of approximately 16% or $2 million per well lower than compared to 2024 costs. That’s a further improvement of $200,000 per well compared to the first quarter of 2025. We remain on track to achieve 2025 budget production of approximately 60,000 barrels per day in the Duvernay, BOEs per day in the Duvernay. North American natural gas production for the second quarter averaged approximately 2.4 Bcf per day, an increase of 14% over the second quarter of 2024.

The Operating costs on our North American natural gas averaged $1.07 per Mcf, which is 10% lower compared to the second quarter of 2024 of $1.19 per Mcf, primarily the result of higher production volumes. In our Thermal In Situ operations, we achieved strong thermal production in the second quarter, averaging approximately 274,800 barrels per day. This is up 3% from the second quarter of 2024, resulting from our capital-efficient thermal pad development program. Second quarter Thermal In Situ operating costs averaged $11.05 per barrel, which is comparable to the second quarter of 2024. At Primrose, we turned to drill a CSS pad in the third quarter this year with production targeted to come on in 2026. At Jackfish during the month of July, we brought on production a recently drilled SAGD path.

At Kirby, we are targeting to bring the recently drilled 5- well per SAGD pad on production in the fourth quarter of 2025. At Pike, we completed drilling 2 SAGD pads, which will be tied into the existing Jackfish facilities and targets to keep the Jackfish plants at full capacity. The first of these 2 pads is targeted to come on in production in the first quarter of 2026 and second pad will be on production in the second quarter. At our commercial scale solvent SAGD pad and Kirby North, we began solvent injection in June of 2024. In the second quarter of 2025, we executed workovers on 2 well pairs to enhance SOR’s solvent recovery and production trends will continue to be monitored over the coming months. 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.

The increase is a result of the reliability enhancement project, eliminating the need for a turnaround at Horizon in 2025 and the Scotford Upgrader debottleneck, which were both completed in 2024, combined with the additional 20% working interest in AOSP acquired in December of 2024. Oil Sands Mining and Upgrading costs averaged $26.53 per barrel of SCO in the second quarter of 2025, an increase of 2% from second quarter of 2024, reflecting the AOSP turnaround in the second quarter of ’25. Our growing world-class asset base is a strategic balanced — strategically balanced across commodity types so that we can be flexible and capture opportunities throughout the commodity price cycle, maximizing value for our shareholders. A substantial portion of our unique and diverse asset base consists of long-life, low-decline assets which have significant low-risk, high-value reserves that require low maintenance capital than most other reserves, making Canadian Natural a truly robust and resilient energy company.

I will now turn it over to Victor for our second quarter financial review.

Victor Clinton Darel: Thanks, Scott, and good morning, everyone. In the second 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 $3.3 billion and adjusted net earnings of $1.5 billion. These results also reflect the turnaround activities at AOSP that were completed in the quarter. Results in Q2 clearly reflect our disciplined approach to capital allocation and where Canadian Natural focused and executed on our 4 pillars, where balance sheet strength and return to shareholders went hand-in-hand with resource value growth and opportunistic acquisitions. Returns to shareholders in the quarter were $1.6 billion, including $1.2 billion of dividends and an additional $400 million of share repurchases.

These returns, including dividend payments and buybacks up to and including August 6, bringing shareholder returns for the year-to-date to $4.6 billion. Additionally, subsequent to quarter end, the Board has approved a quarterly dividend of $0.5875 per common share, payable on October 3, 2025, to shareholders of record at the close of business on September 19, 2025. Net debt levels were below $17 billion at quarter end, while having completed the acquisitions that were included in our 2025 budget. Our balance sheet remains strong, where debt-to-EBITDA was at 0.9x and debt-to-book capital came in at 29.1%. Liquidity of over $4.8 billion was also strong, and reflects undrawn revolving bank facilities and cash on hand. The accretive acquisitions that were completed in late 2024 and year-to-date in 2025 immediately contribute to incremental production and additional free cash flow generation.

Taken together with the strong operational results in 2025, Canadian National targets to provide similar shareholder returns in 2025 as compared to 2024. This is targeted to be achieved despite only allocating 60% of free cash flow in 2025 to shareholder returns as compared to allocating 100% in 2024. Our industry-leading cost structure predictable long-life, low-decline assets and reserve base, combined with a consistent commitment to continue its improvement and ability to execute on opportunistic acquisitions in our core areas continue to drive significant value at Canadian Natural. We maintain our disciplined approach that contributes to our top tier U.S. dollar WTI breakeven that remains in the low to mid-$40 WTI per barrel range, which we define as the WTI price required to generate the adjusted fund flow cover both maintenance capital and dividends.

Returns to shareholders remain a top priority for our focused and dedicated teams. Where our culture and drive to do things right every day continues to enable material free cash flow generation and returns on capital. And those are my comments, and I’ll turn it back to you, Scott.

Scott G. Stauth: Thanks, Victor. In summary, our relentless focus on continuous improvement, combined with effective and efficient operations drove strong performance year-to-date in 2025. Our ability to effectively allocate capital across our strong asset base provides us with a competitive advantage. This ability, combined with our accretive acquisitions create significant long-term value for our shareholders. Our culture of accountability and the strength of our assets is a unique advantage that results in both capital and operating cost savings and maximizes value for our shareholders. And with that, I will turn it over for questions.

Q&A Session

Operator: [Operator Instructions] Your first question is from Patrick O’Rourke from ATB Capital Markets.

Patrick Joseph O’Rourke: I guess first question here is just with respect to liquidity management. As we look out, 2027 is a bit of a heavier maturity year between the term loan and one of your larger nominal debt notes that’s outstanding here. Just thinking about sort of the interplay of tight credit spreads and a sticky end of the long curve, how are you sort of approaching this maturity as we head into 2026?

Victor Clinton Darel: Yes. Thanks, Patrick. It’s Victor here. Good question. I appreciate where you’re coming at it from. 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. But that said, we’ll look to 2026 here. And to your point, look at the refinancing requirements and try to pick an opportune time to do so as we see fit.

Patrick Joseph O’Rourke: Okay. And the second question is sort of more on the operational side. Obviously, it’s probably a smaller asset within the portfolio, but conventional multilateral drilling success here added 26 wells to the program. A lot of smaller peers that are out there talking about secondary recovery, waterflood. We hear a lot on the primary side from Canadian Natural. Can you maybe talk to potential opportunity set for secondary recovery and waterflood in your portfolio there?

Scott G. Stauth: Yes. Thanks, Patrick. It’s Scott here. So we do look at those opportunities as well. Some of the ones you’re mentioning, both on the polymer and the waterflood side. 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. That’s the first area that we’re in, in the Clearwater as well, Patrick. So yes, we are undertaking those activities, along with the multi-let.

Operator: Your next question is from Dennis Fong from CIBC.

Dennis Fong: My first one is obviously, the company has completed a few number of acquisitions over the course of the last several months. Can you talk towards your view of the A&D or M&A environment right now? Obviously, completing some of these acquisitions. How do you — and do you mind touching also as well on your comfort level around the policy environment, how comfortable you feel about adding these assets to your portfolio as well as the opportunity to improve operations, bolster inventory and any other opportunity sets from the acquired assets?

Scott G. Stauth: Thanks, Dennis. Yes, I’d like to speak to the acquisitions that we just recently completed here in June and July. We’ve already talked significantly about the AOSP and the Duvernay acquisition. So we know a lot about that already. But recently with the 2 acquisitions, they’ve come at very accretive for us. They add cash flow for us immediately. I think that’s really important when you look at returns to shareholders, these assets do bring significant cash flow for us. So that’s really how we look at it in terms of — on the M&A side, 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. So it’s a balance between the organic growth opportunities and the accretive acquisition opportunity, Dennis.

Dennis Fong: Great. Scott, my second question moves towards the Oil Sands Mining and Upgrading business unit. I guess on the Albian tour, you guys showcased, obviously, your ability to be quite nimble in terms of opportunities to develop other areas of mine and kind of optimize mine progression, specifically referring to the Sharkbite assets. I was curious as to how you think about Horizon. Obviously, as you’ve layered on incremental land adjacent to existing producing projects. And how you’re thinking about mine progression over the next few years, especially as you’ve added again incremental land or developable opportunities in and around your existing operations?

Scott G. Stauth: Sure. So in terms of Horizon, Dennis, I think if you look at where we’re at now for the next, call it, 7 to 8 years, we’ll be progressing our way through the southern portion of the Horizon mine, which was acquired from Total several years back. Following that, we’ll be moving up to the North Pit, the North Pit extension area, and that’s where we’ll be moving in the next phase of development there to maintain the upgrader production levels to currently what they’re at. In reference to your comments about the additional assets, whether that’s Pure River or the North Pit at 6. Those assets would have — are not booked in terms of reserves. They’re resource for us, but they have significant bitumen in place. and they potentially would be assets that could be developed sometime down the road that would support significant oil sands mining development opportunities.

Operator: Your next question is from Greg Pardy from RBC Capital Markets.

Greg M. Pardy: Scott, has there been a pronounced shift in your mind in terms of how Canada’s Competition Bureau assesses or processes acquisitions. I mean, obviously, when you’re spending 10% of your press release just indicating that you’ve got these deferrals on deals and you guys do deals all the time, it just feels like something is different that might not have been there a year or 2 ago.

Scott G. Stauth: Yes. Thanks, Greg. 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. I do agree with you. It took a longer process than it should have, longer than we would have anticipated. In the end, we were able to close the deal and move along. If we look forward, I don’t anticipate we will see the same type of situation going forward.

Greg M. Pardy: Okay. I’ll shift gears, maybe Victor and Scott, but I mean, obviously, the limited buybacks in Q2 obviously stand out as you’re deleveraging. So Victor, I just want to make sure I’ve kind of got the number, the targeted net debt number is around $17 billion, I guess or so at year-end. Does that then puts you in pretty good stead to achieve that $15 billion net debt target in like next year under futures? Looks like would you expect getting there next year under futures?

Victor Clinton Darel: That’s — we’re still right where we were on the last call. When we look at the back half of last year, we’re looking at coming out of 2026 at that $15 billion target based on the current forecast, Greg. I think the rate of buyback to your point, still remains fairly strong. We look at that on an annualized basis, the rate of buyback here in Q2, very similar to what we saw in Q1. And the current forecast, we’d expect a strong rate of buyback here over the last half of the year as well. So no real change in the policy there.

Greg M. Pardy: Okay. So no change in the policy, but — and I’m splitting hairs, but getting to $15 billion before December 31 is not unrealistic. Is that fair?

Victor Clinton Darel: That’s fair. Yes. We’re looking at that in that $65 to $70 WTI range. So obviously, it depends on pricing here coming into 2026.

Operator: Your next question is from Manav Gupta from UBS Financial.

Manav Gupta: I have 2 questions. I’ll ask them upfront. First, I wanted to — if you could help us understand the benefits of closing the AOSP deal with Shell, how much volume comes in? But would that change the way you look at the mine also, could you increase your bitumen output because you don’t have to match the upgrader? And then second question is, can I get your outlook on the AECO pricing and going forward, especially with the LNG Canada also starting up?

Lance J. Casson: Yes. Thanks for the question. I’ll answer the second part first, with LNG Canada coming online, I think if you look at the forward strip, the pricing still does look soft. In terms of AECO. I think the market is probably anticipating certain amount of gas that we’ll easily be able to be turned on. Our view, though, is that once the second train is brought online, that there will be definitely a period of time that it will take to fill up the full 2 Bcf of capacity of LNG Canada. So I would think that we’re going to see ebbs and flows in terms of AECO pricing and its relativity to what the basin is able to produce for total egress capacity. I think that will ebbs and flows in the next 5-plus years. And on your — sorry, could you repeat the first question for me?

Manav Gupta: How does the AOSP transaction change the outlook? And is there a way you would change the mine also just because probably you can produce more bitumen. I’m just speculating because you don’t have to match the upgrader, but if you could talk about how the transaction changes your ability to operate the ASP mine once you do become 100% owner?

Scott G. Stauth: Right. So just to clarify for you, the swap involves Canadian Natural acquiring 31,000 barrels a day of bitumen production. So that’s important to us. We see 100% ownership of the mine important to us just from a synergies with Horizon perspective. We will no longer have a JV in terms of the mines. It’s easier for us to be able to move our equipment back and forth, whether that’s heavy haul trucks, cranes, people and other types of assets that we can move back and forth to optimize and warehousing is another one that we look at where will no longer have to maintain 2 separate warehouse. Warehouse is where you would have one at 90% and the other one at 100% working interest. So those are all items that are small in nature, but they do add up.

So we see some important synergies coming through that. Now in terms of going forward for production opportunities, I think we’ll talk more about that probably later this fall. We’ll have some more in-depth discussions that we can form of what our views are on the long term. And of course, all that’s going to be relative to where we see pricing WTI and bitumen pricing over the long term. But I can tell you that there are significant opportunities both at Horizon and AOSP to increase production.

Operator: Your next question is from Neil Mehta from Goldman Sachs.

Neil Singhvi Mehta: I want to say on the marketing theme here and just talk about the WCS heavy differential. Obviously, year-over-year, we tightened up nicely, but we’ve seen it widen out here. And just your perspective on whether this tightening that we’ve seen more recently is structural post TMX and given the tightness of heavy on the Gulf Coast or as OPEC brings barrels back online and Canadian production does seem like it is growing that we’re going to move back to, let’s call it, the $13 run rate you were at — most of last year into early this year.

Scott G. Stauth: Good question, Neil. I think the way to look at it is we would anticipate the WCF differential to vary in the range of $10 to $13. There’s going to be timed it could be more than that or wider than $13. There’s going to be times when it will be lower than $10. And yes, that will vary dependent on OPEC production potentially. It also has impacts just within North America in terms of the refinery turnaround timing. And so those all — those situations are going to impact it, but the structural change happened when TMX came online in May of 2024. We anticipate the differentials will be in a pretty solid range bound at $10 to $13.

Neil Singhvi Mehta: Okay. That’s really helpful. The same question on the SCO premium. We obviously had a lot of maintenance in the second quarter as it relates to the upgrades. It had been kind of bouncing at a discount of a couple of bucks up until this point. SCO also is influenced by the strength of distillate, which trades at a decent premium to no gas right now. So how are you guys thinking about pricing relative to TI?

Scott G. Stauth: Again, I think same type of scenario, probably you look at a range bound of minus 1.5 to plus 1.5. It’d be somewhere in that range, Neil. And of course, you mentioned on the distillate side as well. So — and you’ll have time to the year where we saw strong Q2, as you mentioned, related to maintenance. So I expect to have some flows to move on a go-forward basis, just like they have done in the past relative to turnaround activities. And so if you look back over time, that differential has — it has varied from minus 2 to plus 3. And so I don’t think you’ll see any structural shifts going forward here.

Operator: Your next question is from Menno Hulshof from TD Cowen.

Menno Hulshof: I’ll start with a question on synthetic. You talked about 602,000 barrels a day for the month of July. With little to no turnaround activity tied to SCO production in the second half. What could get in the way of you being able to maintain 600,000 barrels a day or even a bit higher through the end of the year?

Scott G. Stauth: Yes. Good question,. I think we should be looking within that range. There isn’t anything necessarily stopping us. We have the turnarounds that have been worked through at AOSP and Horizon has — all things look really good at Horizon as well in terms of the upgraders performance. So you would have noted, we had a very strong Q1, where everything went very well for us, really solid road conditions through the winter time. You don’t quite see those solid haul road conditions in the summer and fall that you do in the wintertime. But in that range, in that 600,000 range, I think, is probably a good run rate to consider now.

Menno Hulshof: Okay. And then flipping over to turnarounds. You had the 5-day acceleration at the ASP in the quarter. That seems to be a trend. We’ve seen similar updates from some of your peers, including Suncor yesterday. So my question is, what is driving better-than- expected turnaround execution for yourselves? And then on a related note, how much contingency is typically built into the time line for a given turnaround?

Scott G. Stauth: Yes. Really good question. For us, I would say that the opportunities such that happened here with being 5 days early at AOSP. It’s really just a matter of — if you look at all the manpower required on site, we’re driving for efficiencies, lots of labor required taking units apart, doing inspections, doing cleaning of vessels and so on and so forth. The teams that are driving those turnaround activities are — have that same continuous improvement culture that we do have with the rest of our operations in the company. So they’re expected, and they do look at ways of trying to find efficiencies, Menno. So really, there isn’t a lot of built-in contingency probably in the 10% range of estimates when they’re building their turnaround schedules.

So they’re enticed and we certainly encourage the teams to continue their opportunities that they look at to create those efficiencies and find ways to have the manpower on site be more effective and more efficient.

Operator: Your next question is from Doug Leggate from Wolfe Research.

Unidentified Analyst: It’s [indiscernible] on for Doug Leggate. I just wanted to kind of get some insight to get your view on when do you see capacity to grow the dividend, especially in light of some of the acquisitions that were described on the — in the press release and on a go-forward basis?

Victor Clinton Darel: Thanks for the question. Obviously, we’ve had a long history of growing the dividend every year now for 25 years. There’s definitely some good incremental cash flow coming off the acquisitions. I wouldn’t want to step into the Board shoes there, but I would just say that as we go forward, I’d anticipate that there’d be some room for dividend growth here into 2026 should the Board continue to pursue the track record that we have seen in the past.

Scott G. Stauth: And Nick, I would just add to that. If you look at the history of the company over the past 25 years, the opportunities for the Board to consider adding an increasing the dividend payout has come on the backs of both organic and opportunistic acquisition opportunities that the company has taken on over the past 35 years. And I think that’s really important to remember the future doesn’t always represent the past, Nick, but for a company with the strength of the assets that we have, it is extremely important to the Board and to the management team to maintain the dividend, the value of the dividend that has been brought to the shareholders, and it’s very important to us. So we’re going to make sure that we continue to operate our assets and grow organically and find opportunity to acquisitions when we can to help support continued growth of that dividend.

Unidentified Analyst: Thank you. And for my follow-up kind of ties into that. So where do you kind of see your post-dividend breakeven right now for your metrics? And is there a threshold that you’re comfortable — I guess, what’s the threshold that you’re comfortable kind of taking it from its previous, I guess, $1?

Scott G. Stauth: You’re asking what our breakeven is, Nick?

Unidentified Analyst: Yes. yes. I’m asking what is the post dividend breakeven currently? And is there a range that you’re looking to kind of stay within, I guess, as you kind of feel comfortable and maintain your balance sheet?

Victor Clinton Darel: Yes. So currently, we’re in that $40 to $45 WTI breakeven range, and the incremental cash flow from the acquisitions is keeping us there. We do, do that calculation post dividend. The dividend is something that we consider very valuable shareholders and shareholder returns. So that’s — we calculated after the dividend.

Unidentified Analyst: And is there a threshold and that the targeted threshold that you’re looking to stay within the $40 to $45 range essentially?

Victor Clinton Darel: We’re comfortable in that range now. So essentially, the answer is yes. And obviously, we take a view to commodity prices going forward and as the Board assesses that in future periods.

Operator: [Operator Instructions] There are no further questions at this time. Please proceed with closing remarks.

Scott G. Stauth: Thank you, operator, and thanks, everyone, for joining our call this morning. If you have any questions, please give us a call. Have a great day.

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