Whitecap Resources Inc.

Good morning. My name is Joanna, and I will be your conference operator today. At this time, I would like to welcome everyone to Whitecap Resources' second quarter 2025 results conference call. All lines have been placed on it to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number one on your telephone keypad. If you would like to withdraw a question, please press star, then the number two. I would now like to turn the conference over to Whitecap's President and CEO, Mr. Grant Fagerheim. You may begin your conference call.

Thanks, Joanna. And good morning, everyone, and thank you for joining us here today. There are four members of our management team here with me today, our Senior Vice President and CFO, Ton Kang, our Senior Vice President of Production and Operations, Joel Armstrong, our Vice President on Conventional Division, Joey Wong, and our Vice President, Conventional Division, Chris Bullen. Before we get started today, I would like to remind everybody but all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory that we set forth in our news release issued yesterday afternoon. To begin, it would be remiss of me to not highlight the most significant development of the quarter, the completion of the Varum business combination on May the 12th, which has increased our production to approximately 365,000 BUE per day and our enterprise value to over $15 billion. I'm also pleased to report that we had a very successful operational second quarter, continuing to build on the momentum that we've developed year to date. Strong second quarter production of 292,754 BUE per day was well above our internal forecast as an asset level performance exceeded expectations across our conventional and unconventional portfolios. Our production in the quarter benefited from strong new volumes across our Montney, Duvernay, and southeast Saskatchewan assets, as well as production optimization through downtime avoidance within the Duvernay and the Glauconite formation. As referenced earlier, we successfully closed our strategic combination with Barron during the second quarter on May 12th, representing a transformational milestone for the company. The newly expanded Whitecap is now Canada's seventh largest oil and natural gas producer and fifth largest natural gas producer, with an exceptionally deep portfolio of a premium drilling inventory for advancing incremental growth and value added for our shareholders. As a result of the significant effort and coordination among our various team members, the integration of the Varon assets and staff has been successful in a remarkably short period of time. We've seen plenty of early wins through the consolidation of corporate costs and our improved credit profile. By leveraging combined best practices and our enhanced scale, we are expecting to see capital efficiency improvements and operating cost reductions across the portfolio. We remain confident in our ability to unlock sustainable synergies and look forward to updating shareholders as our programs over the next six to 12-month period of time. Through the second half of 2025, we plan to allocate 75% of our capital program to our unconventional Montney and DuVernay assets, where we currently have seven active rigs running and focused in areas where we have strong technical understanding with available infrastructure capacity. The remaining 25% of our second half capital program will be invested in our conventional assets in Saskatchewan and central Alberta. We currently have three active rigs on our conventional assets, peaking at eight rigs in the second half, building off the strong momentum of the first half program. We will continue to stay on the course on strategic priorities that have underpinned our success to date. including maintaining our balance sheet strength, capital discipline, and providing sustainable returns to our shareholders. Our balance sheet is in excellent shape, with low leverage and ample liquidity. Our flexible capital program and sustainable base dividend of 73 cents per share per annum remain well covered within funds flow at current commodity prices, supported by our best-in-class portfolio of assets. I will now pass off to Joy Wong, for more remarks on our unconventional results.

Thank you. Thanks, Grant. We delivered strong operational performance across our unconventional portfolio during the second quarter, while working diligently to integrate new assets and personnel across the combined Montney and Duvernay asset base. We've seen early operational wins from the integration of the combined assets through knowledge sharing of technical best practices, the optimization of rig lines, and initial procurement optimization efforts. Our Duvernay production at KBOB was a notable driver of unconventional outperformance during the quarter. Production was higher than forecast as strong operational execution accelerated new pad development into the quarter, and downtime optimization allowed us to mitigate the impact of turnaround activity at our operated 15-7 gas processing facility. We were also successful in mitigating the impact of an extended outage at a third-party facility in the area as adjustments were made in the field by our field operations team to limit our exposure. We recently brought our third wine rack style pad on production through permanent facilities in KBOB with promising early results. Strong observed reservoir performance and positive production results across our first three wine rack pads support moving this design from pilot to development mode on applicable lands in our KBOB asset. This wine rack design has the potential to improve per well recoveries and associated well economics on over three quarters of the undeveloped legacy whitecap acreage and just under a quarter of the barren acreage. Our measured approach to delivering optimized and predictable results in the DuVernay demonstrates our commitment to enhancing returns and maximizing our high-quality inventory in our unconventional asset base. We acquired our first DuVernay assets in the second half of 2022 and at that time underwent a rigorous technical review. As our understanding of the assets grew and our development program matured, We outlined specific goals for our team, which included the acceleration of development and the full utilization of our 1507 gas processing facility to maximize overall asset profitability. We are pleased to report that we are now at capacity at that facility. As an example of the improved profitability of the asset, the second half operating costs on our legacy white calf acreage are forecasted to be 30% lower than what was realized in 2023. Further, to facilitate additional growth in the area, we have completed the construction of an offload connection to a nearby third-party processing facility. The integration of Duvernay assets at KBOB has been quite seamless, given the significant overlap and stage of development. As the largest operator in the Duvernay, we now have the size, scale, and technical capabilities to further improve profitability on this well-understood asset base. Moving over to the Montney. 12 Montney wells at Gold Creek and Carr were brought on production during the first half of the year. Overall results in this area are performing in line with our internal expectations. We are in the process of assessing the impact of changes in development planning and well design in Gold Creek and Carr, leveraging recent and legacy pad results along with the significant technical expertise of our teams. Our focus remains on enhancing well economics and the long-term potential of the assets while balancing our risk exposure, consistent with how we've approached development across our unconventional assets over the years. We are now seeing improved infrastructure reliability and utilization across our Gold Creek and Carr assets, as we reach the benefits of significant infrastructure optimization efforts in the first half of the year. Key upgrades included enhancements to support existing production, including improvements to gasless capacity, and several de-bottlenecking projects that have improved overall operability and consistency. The impressive results have continued at our Musrell Monty asset, giving us the confidence to begin drilling larger pads to further target capital efficiency improvements in the area. We are currently drilling a six-well pad, which is expected to be on production in early 2026 when additional plant capacity becomes available. Our investigation of de-bottlenecking options to increase gas throughput at our 5 and 9 facility also remains underway. At CAQA, we recently brought on our first triple bench pad on production at 16 of 17 in the northwest portion of our acreage. Initial rates on the test pad after 90 days are over 1,200 BOEs per day per well with 65% liquids exceeding our internal expectations for the area by 14%. These results are encouraging and provide significant validation points for this pad configuration. Importantly, the triple bench design is behaving as expected based on our technical observations thus far. Further observation of bottom wall pressure trends will be collected in the coming months and will be informative as we continue to assess the development potential of this pad moving forward. At Latour, phase one of our 413 Latour facility remains firmly on schedule for commissioning in late 2026 to early 2027. We've now received all the required permits to begin construction and as a result have initiated earthworks on the site. All major equipment has now been procured for delivery in the first quarter of 2026. Strong performance from our two Latour delineation wells brought on production in 2024 has continued. Each of these wells has exceeded internal expectations by 20%, providing us with the confidence in the reservoir deliverability in the area and our long-term development plans. We will continue to advance our technical delineation program by drilling a three-well pad in the area late in the third quarter. As the most analogous data in our modern well set, Our Latour Wells also provide an important technical read-through for our adjacent rest-saving asset. With that, I will now pass over to Chris Bullen to talk about our conventional assets.

Thanks, Joey. Our conventional portfolio continued to build on strong momentum from our first quarter program with results from our publisher, Lopity Cardium and Glockonite Assets, all continuing to outperform expectations. The newly integrated Bufield Bakken assets also delivered strong production performance in the quarter, highlighting the immediate strategic fit of Baron Saskatchewan assets within our conventional portfolio. I'd echo Joey's comments that we've seen some early operational wins from the integration of assets on the conventional side, largely through shared technical learnings between our teams and initial supply chain optimization efforts. We continue to advance open-hole multilateral development across both our Bufield Bakken and Frobisher assets in eastern Saskatchewan during the second quarter, with results exceeding our expectations in both areas. Based on the success of our open-hole multilateral program in these regions, we continue to evaluate opportunities to enhance economics and expand drilling inventory by applying this technology elsewhere within our conventional portfolio. At Bufield, our five most recent Bakken wells have exceeded our tight-curve expectations by 27%. As part of our focus on enhancement initiatives, our team has recently begun piloting longer laterals in the Bakken to increase reservoir contact and improve the already strong economics. Early time results from our first two and a half mile open hole multilateral well are promising, and we just spotted our first three mile pilot well in the area. In the Frobisher, our active first quarter open hole multilateral program is forecast to achieve a 25% capital efficiency improvement compared to the same period last year. This is achieved through a combination of program efficiencies and optimization of individual well designs to maximize reservoir contact, well productivity, and the royalty benefits associated with Saskatchewan's multilateral oil well program. We are excited to deploy Whitecap's Frobisher development experience to the recently acquired inventory and are continually evaluating additional synergies to reduce costs and enhance future locations. In our Alberta conventional assets, results from our recent cardium wells at Wapiti also continue to significantly exceed expectations. These wells utilize an optimized completion design established using workflows from our unconventional assets. Our first six wells have been on production for approximately 180 days, achieving rates that are on average 59% better than our expectations. By confirming that the longer-term value has also been increased, we plan to deploy this design on future wells in the Wapiti area and are evaluating recent results for re-trues on similar assets within the portfolio. In our guacanite asset, recent facility egress optimization efforts by our team enabled us to redirect turnaround volumes in central Alberta and mitigate the production impact of planned downtime during the quarter. Along with continued strong results from our monoboard drilling program, this drove production outperformance relative to our internal expectations in the area and is driving improved profitability since our entry into the play. The free cash flow generated by our conventional division is underpinned by over 50,000 barrels a day of stabilizing EOR volumes across both Alberta and Saskatchewan. These assets are important to the long-term sustainability and profitability of Whitecap. I will now pass it to Tom to further discuss our financial results.

Thanks, Chris. The second quarter fund flow was strong at $713 million, or $0.75 per share, which was up 6% per share compared to the second quarter last year and 2% compared to the first quarter of this year. Despite the volatility, WTI prices averaged just below U.S. $65 per barrel in the quarter, which equated to over $88 per barrel Canadian, driving strong profitability for Whitecap. The positive impact of the startup of LNG Canada has yet to be reflected in ACO prices, with the second quarter averaging less than $2 for MCF and July even lower than that. We have reduced our ACO exposure through the combination with Barron and currently have approximately 30% of our natural gas production sold outside of ACO and a further 30% sold at fixed prices. Whitecap generated strong free funds flow of $304 million, of which $191 million was returned to shareholders through the base dividend and share repurchases. In the first six months of 2025, we returned almost $300 million to shareholders. We had a tax recovery of $7.4 million as commodity prices in Q2 were lower than in Q1, and with the tax pools at the end of the quarter of approximately $10.3 billion, we anticipate taxes as a percentage of pre-tax funds flow to be 3% to 5% in the second half of the year. We were also able to take advantage of the commodity price volatility and the price spikes we experienced during the second quarter by adding approximately 10,000 barrels per day to each of our second half 2025 and 2026 hedging positions through a combination of callers and swaths to lock in additional downside protection. Our balance sheet at the end of the second quarter was in excellent shape with net debt of $3.3 billion, equating to a net debt to annualized fund flow of approximately one time. Following an upgrade of our public investment grade rating to BBB by DVRS, we closed an issuance of investment grade senior notes in the quarter. The three-year, 300 million notes carry an attractive fixed coupon of 3.761% and lowers our average cost of debt. With that, I'll turn it back over to Grant for his closing remarks.

Thanks, Todd, Chris, and Julie for your comments. Since the close of the Varon combination, our combined team has done a remarkable job of integrating assets, people, and processes, all while delivering another outstanding operational quarter. Based on our asset level performance in the second quarter, we now expect to be at the high end of our 2025 average production guidance range of $295,000 to $300,000 per day on an unchanged capital budget of $2 billion for the year. As we begin our 2026 budgeting process, our outstanding suite of assets provides us with significant optionality across the commodity spectrum, from light oil to condensate-rich natural gas, to natural gas opportunities. This allows us to tailor our future capital program to commodity pricing and maximize our long-term value creation. With our enhanced long-term sustainability and profitability, we are well-positioned to generate superior returns for our shareholders and look forward to providing updates as we advance forward. With that, I will now turn the call over to the operator, Joanna, for any questions you might have. Thank you.

Thank you. Ladies and gentlemen, as stated, if you do have a question, please press star followed by one on your touchtone phone. You will hear a prompt that your hand has been raised. And should you wish to withdraw your question, simply press star followed by two. We do ask that if you are using a speakerphone to please lift your hands up before pressing any keys. Please go ahead and press star one now if you have a question. The first question comes from Dennis Fong at CIBC World Markets. Please go ahead.

Hi, good morning, and thanks for taking my question, as well as congratulations on a really strong start to the integration and quarter. My first question goes towards commodity risk, or sorry, commodity price risk management. You both obviously layered in a little bit more on the hedging So I just think as you kind of look forward, can you remind us as to kind of what you're targeting, how that maybe helps both obviously dividend sustainability as well as we'll call it downside risk protection and how you think about things going forward, especially in terms of management around that risk.

Yeah, thanks for that question, Dennis. It's Tom here. So the way that we look at risk management is really ensuring that we have the cash flows in a low commodity price environment to fund their maintenance capital as well as their dividends. So we would target somewhere between 25% to 35% on a two-year rolling basis to ensure that we meet that objective. So when you look at our positions now, both on the oil and the natural gas there, we're right within the range of what our expectation is. We've got really strong positions for 2026. In the back half of 2025 here, we're going to start layering on positions for 2027 there. So, again, the objective here from the hedge positions that we have is really to provide that downside protection. And so when you look at the positions that we have, they're typically just callers, costless callers, as well as swaps. So plain vanilla positions to mitigate that downside risk.

Great. Thanks.

Really appreciate that incremental call there, Tom. Shifting a little bit more on the technical side and maybe directed towards Joey or Frank there, I was hoping you could highlight maybe some items that you're focused on in terms of some of the key takeaways. I guess beyond well productivity in both the wine rack style development, you're playing a K-bob, as well as the triple bench strategy in the money. What, frankly, drives your confidence, obviously, in the deployment and all these development techniques? And what would drive you to gain more comfort or confidence in rolling that out more broadly to other regions as well?

Hey, Dennis, Joey here. So, yeah, maybe I'll touch on the KBOB one because it's a good example there. Like I mentioned, we're at our third tab there. So when we look at – development, we look at both rate and pressure directly, as well as the interpreted versions of that data that our reservoir engineering team looks at using established reservoir engineering best practices. We look at observations of things like frac geometry and reservoir contact, and of course those are things that we can look at early time, and on all three of those paths they were looking great, so that was supportive of moving forward with further pilot. But then as we started to produce the wells, and we look at how not only do the individual wells perform, but then how they interact with each other and offsetting wells, we were continuing to see supportive indications from downhole. So that gave us then the confidence that, okay, these things are producing in line with our expectations in the longer term. And in particular, with the first couple of pads having quite a bit of time there, being able to really now reinforce the models that we had in place to give them that read-through to the balance of the asset base. Maybe that brings to the second part of your question is what gives us the confidence if we have an established geological model, which we do throughout the Duvernay, we have an estimate of how these wells should behave with this adjustment in development, and it conforms to that, or in this case actually quite honestly slightly exceeds that, we then can say, okay, this works. And that's where we came up with the high confidence three-quarters of the white cap and roughly one-quarter of the barren asset base that would be applicable to that. Beyond that, we'll continue to see if we can push the limits of that. Okay, we have high confidence it works on those, and for context, we're saying somewhere in the range of 10% to 20% improvement. We'll bake that into our tight curves. We'll then look to set beyond that and say, okay, are there marginal lands beyond that that can see subsequent improvement or adjustment to their design in keeping with that. And that whole theme that I spoke to there just on the Duvernay, that's kind of an anecdote that you can kind of envision us going through on the entirety of our asset base when we introduce something like that.

Great. Thanks, Joey. And if you'll allow me just one quick incremental one. Just as, and maybe to the corporate strategy side of things, As you shift away from kind of significant growth profile as maybe outlined by Barron and look towards kind of drill-to-fill opportunities, obviously you've filled some of your gas plants and so forth, now looking at the bottlenecking opportunities, as well as optimization on the conventional side. Can you talk towards how you're thinking about decline rate and the management of sustaining capital going forward and how you think some of those inputs could drive better sustainability of the business model going forward?

Thanks.

Yeah, that's an important part of our sustainability there, Dennis. And so as we think about the conventional and the unconventional side, as you know, the conventional side, what we're looking to do is really just maintain that production rate. And so it's underpinned by 40% of that production being under some sort of secondary tertiary recovery there, so a decline rate of less than 20%. As we maintain that production, I'd expect that to be relatively flat, I would say, And then on the unconventional side, the objective there, the 225,000 DOEs per day, is to grow that in that 8% to 12%. Again, depending on what the corporate objective there is on an annual basis, as well as commodity prices here. But we see over the next five-year period of time there, the decline rate up somewhere in that 1% to 2% there on a corporate basis. And so... As we look at that, it's still very manageable, especially with the 140,000 BOEs per day that we have as the base level that underpins the sustainability of our cash flows.

Thanks, Tom. I'll turn it back.

Thank you.

The next question comes from Travis Wood at National Bank Financial. Please go ahead.

Yeah, good morning, guys. Hey, so appreciating the unconventional portfolio gets a lot of airtime. It does feel like the conventional segment performed quite well through the quarter, and maybe most notably there, the cardium wells that you flagged at Wapiti. Could you guys walk through or share some insight around what drove that outperformance on those IP rates that you flagged in the release and what the running room and infrastructure capacity looks like in the region as well?

Yeah, morning, Travis. Chris here. Thanks for that question. So, with regards to the Wapiti Cardium, you know, the team's pretty excited about some of the recent results, of course. And, you know, what this ties into, in essence, is really trying to maximize our reservoir contact, you know, drilling longer wells where we can, common theme on our conventional assets. in conjunction with, you know, using some of the established workflows from the unconventional side. So what we've done by that is really just optimizing our frac design with some tighter cluster spacing and some higher profit intensity, and that's really been the key driver on some of those IP90 and IP180 early time results. So obviously we're quite excited about that, and, you know, the teams are currently going through a bit of a workflow process right now to update our type curves going forward. Now, from a running room inventory perspective, we're feeling pretty good about that area. We've got about 60 to 80 locations identified there. From our perspective, I mean, that provides, you know, more than five years of running room, and that's not even including some of the upside the teams continue to work on. So we're pretty excited about the area. You know, at that pace of development, we don't see any egress concerns or challenges there. And, you know, in the theme of a lot of our conventional assets here, you know, we're hoping to provide that stabilizing and steady free cash flow throughout. So, yeah, key takeaways, a lot of shared learnings, and, again, just trying to maximize that reservoir context. So our teams have done a great job there.

Great. And Chris, did you say at that running room, there's no egress constraints? Is that what you said?

You know, from our perspective, we're not trying to, you know, pull the lever hard from a growth perspective. I mean, we do have growth optionality within those assets, but in general we're looking at, you know, flat to call it 2% to 5% growth in that area. We do have some additional options, and the teams are always working at ways to maximize, you know, egress options. Another example of that would be, you know, pivoting to our Glock portfolio where we have a very advantageous position and, you know, infrastructure that's vastly interconnected. We're always looking at those kind of options up there, too. But at the current time, with our development pace and, you know, kind of our prelim five-year plan, we're looking very confidently that, yeah, there's not going to be a concern at that pace.

Okay. That's perfect. Really, thanks for the detailed rundown.

I'll leave it there.

Thank you. The next question comes from Sam Burwell at Jefferies. Please go ahead.

Hey, good morning, guys. Grant, I wanted to get your thoughts on the needs for any incremental crew egress out of the basin, especially beyond what's been floated by Enbridge already and being cognizant that you're not fully utilized on TMX or Keystone right now. So, just curious what you thought the needs might be.

Yeah, thanks very much, Sam. Again, this is Grant. Just on the incremental egress that We don't think, specific to light oil, that there's challenges with light oil out of the basin. I mean, we're not part of, we don't ship west on what GMX is, and mainly what we'll call a heavy oil pipeline. As far as any challenges on egress moving into the U.S. or east, because of where our light oil is located in southeast Saskatchewan, for the most part, we don't see egress challenges at this particular time. And I want to back up, even through what we talked about in Canada, we had where there was apportionment. I can tell you through the entire timepiece that you would hear about apportionment of volumes. We never restricted one barrel a day of production through what was a very heavy apportionment period of time back in history. So I think we're very well set up from an egress incremental egress perspective or just even the current egress. And we think that with Enbridge and any of the pipeline providers looking to optimize, whether it's TMX or Enbridge or doing some optimization to their lines, we certainly don't see any challenges for the foreseeable future.

Okay, great. That's what I got. Thanks.

Thanks, Sam. Thank you. The next question comes from Aaron Bulkowski at TD Cowen. Please go ahead.

Thanks. Good morning. I guess my question, I'll have to preface by saying that I understand the value comes from the integration of VARIN with Whitecap's legacy assets. But if you're able to segment the data, I'd be really curious to know what Whitecap contributed to Q2 and what VARIN produced in Q2 if you had owned an entire period.

Yeah, it's Tom here, Aaron.

I mean, the way that we look at the business, quite frankly, is on a consolidated basis. And so, you know, all these assets now combined as white cap resources. I will comment that, you know, when we look at the production outperformance, you know, 12,000 DOEs per day relative to our internal forecast, about 8,000 of that was attributed to white cap performance on a standalone basis, and 4,000 of that was attributed to the VAREN assets. But certainly on a go-forward basis, you know, we're obviously reporting everything on a consolidated. And so we'll talk to it on that basis.

No, that's perfect. If I could ask one more follow-up question. I'd be curious if you get incremental free cash flow tailwinds relative to what you're budgeting internally. How do you prioritize that between paying down debt faster relative to buying back stock sooner?

Well, I know what Grant would say.

Certainly buying back shares would be a priority for us, I would say, Aaron, relative to where the stock price is and our intrinsic value. When we look at the balance sheet today, at the end of the quarter, we were $3.3 billion. I'd say that our target at the end of the year would be somewhere between $3.3 to $3.5 billion, which is one-time debt-to-cash flows. And even if we're stress testing that down to $50 oil, that'd be 1.2 to 1.3 times cash flow with more than sufficient liquidity. So the balance sheet is in excellent shape. Now, what I would say, though, is longer term, as we think about the cyclical business that we're in here, we do want to continue to build up that dry powder and continue to capture opportunities for our shareholders. And so debt target longer term would be somewhere between $2.7 to $2.9 billion which would be one times debt to cash flow at $50 WTI. But certainly with the strength of the balance sheets that we have today, that doesn't preclude us from buying back shares.

Very helpful. Thank you very much.

Thanks, Eric. Thank you.

The next question comes from Patrick O'Rourke at ATP Capital Markets. Please go ahead.

Well, hey, guys. Good morning, and thank you for taking my question. I guess just first question here, in terms of the synergies that were announced with the deal in the range of $200 million there, now that you've had a chance to integrate the teams here, are you able to better triangulate for us sort of the pace that you anticipate achieving that? And then obviously you talked before about very high-level management being involved in the deal. Now that you have these teams integrated, what's sort of the scope of the upside above that $200 million that you're starting to think about?

Yeah, thanks for that question, Patrick.

It's Tom here. You know, as you know, this was a transformational acquisition for us. And, you know, a lot of people process the systems to really integrate and bring forth. I mean, we closed on May 12th here. I think as we look at the synergy number there, the corporate savings, $35 million that we've outlined here, with the reduction in the staff that we've brought over, as well as our improvement to our credit profile with the BBB rating from DBRS, I think that one we've pretty much achieved here. I think the remaining one that you're referencing with respect to the capital as well as the operating there, again, want to make sure that we really involve the teams. in terms of building that out. I would say that, again, the realization of them will be over the next six to 12 months. And where we really will look to incorporate that would be in our 2026 budget there. So looking to release that early in November. So that would be the expectation. I think that given the magnitude of the acquisition here, it's still really too early to say what the upside is over and above the $175 million that we've outlined.

Okay, great. And then you guys gave a very detailed sort of rundown on the wine racking and the duvernay, but I was just wondering if you could give us a little update with respect to what's going on at Gold Creek. I know it says that you're sort of assessing the technical data there. So what's the timeframe you think before you can start achieving optimization on that asset?

Hey, Patrick, Joe here. So

The concept of optimizing, I would say, is going to be a progression. So early things that we've been able to do to optimize on the incoming asset base, things like adjusting, maybe think about the Duvernay for a quick second here, we're plug-and-purp, we're still being employed by Barron. Adjusting things like the perforation and cluster design, that's something we can kind of do early time, and that'll have a certain amount of marginal gains We'll also be looking at early time here as well, and this applies to both Gold Creek Car and as well as the DuVernay, doing the frack operations by utilizing our frack room and calling those fracks from Calgary, hoping to see some incremental gains from that. From there then, what we'll expect to then do is make some more structural changes to the program, things like well spacing, benching, overall allocation of capital throughout the fields to balance activity and infrastructure, Those ones will come with a bit more time. And, again, that's more in that 6- to 12-month time frame that Tom referenced there. But early signs are looking encouraging that we will be able to start to realize a lot of the things we were hoping to do.

Okay. Thank you very much, guys.

Thank you.

As a reminder, ladies and gentlemen, if you do have any questions, please press the star followed by the one on your touch-tone phone. The next question comes from Michael Speicher at HCM. Please go ahead.

Good morning, guys. Congrats on some folks are calling the greatest quarter in upstream history. I have one small question and one big picture question. My small picture question is on the Rest Haven 1335 well. That has produced flat at $9 million a day now for, I don't know, 10 months. Last quarter, you guys said – condensate yield that was something like 260 barrels a day. Just relative to your guys' expectations, how's that well looking and what are that key learnings for that 63 township and moving south into West Haven there?

Hey, Michael, Joey, I can take this one as well. So yeah, definitely clear in the public data there that That well has been quite flat. Actually, we're going through a staged increase to production there. Given that that was a delineation well, it was something we wanted to very intentionally hold that rate flat and use that quiet production period to observe what the pressure was doing. And quite honestly, it has been exceeding our expectations by a certain amount. So what we'd look to do there is we're going to start to stage up the production in a couple of deliberate steps there. just to see how much more room does exist on that. So I guess the thought there is that we'll use that as a as essentially a proxy for what the southern portion of that Latour land base would do. And then, of course, use the reference there. It is on the border of our Resthaven asset there as well. Again, we've spoken to how Resthaven is not currently going to be featured in our five-year plan, but still important to understand from a subsurface point of view how that will behave with a modern completion and with our eyes on the bottom hole. With respect to the condensate, your question there, and the gas and everything, the rates, they are still holding well above our expectations there at this time.

Awesome. Thanks, Joey. And the kind of bigger picture question is the conventional portfolio. You guys have had some wins, Charlie Lake at Valhalla, the Monty at Valhalla. When you're thinking through the portfolio, portfolio kind of over the next 10 years, right? White cap has changed quite a bit. Pulling forward some of the conventional value, do you see that through divestments or accelerating kind of opportunities that you have when the cash becomes available? So, does a conventional portfolio become a playground or more of an investment pipeline kind of thing?

Yeah, thanks Michael. It's Grant. We think that the the conventional portion of our assets is stabilizing and very important to the organization long-term. So when we talk about stabilization, we're talking about production stabilization as well as cash flow. The net backs are very, very high there because of the light oil component or the high level of condensate. So from our perspective, I don't know if from my vantage point, if I call it a playground, but it will be an area where we put – incremental capital to work as we advance forward. So, and a lot of this, you know, we talked about it earlier, referenced it earlier, you know, with the spectrum of assets that we do have from light oil to liquid-fetched natural gas to higher component of natural gas, we've got the optionality on any of these particular areas. So, having the optionality on these assets longer term, you know, the conventional portion of our business is not. We're not looking to divest of that. that region, we think it's very important for the ongoing stabilization of our production and cash flows as we advance forward. And we talked about the decline rate in that area being, you know, sub-20%, and 40% of that production is under some form of secondary or tertiary recovery. So we'll continue to advance those programs as we have well, which are very technical in nature.

Awesome. And just one more if you'll tickle me here. You guys divested the Belle Plaine Carbon Hub this quarter to entropy. So, does this change your view on secondary or tertiary recovery in Saskatchewan, or has there been kind of a change with the North Dakota import pipeline, where you were able to secure carbon dioxide for Weyburn over a longer period, or what catalyzed that shift away from CCUS and the Wolf and the Rolling Hills divestment kind of happened?

Sure. I mean, quite frankly, the way we're thinking about the business emission reduction programs in our organization are very important as a longer term. When we find specific to the new, we'll call it new carbon capture hubs or CO2 hubs that we've been advancing and The return characteristics are so small relative to what we can get in conventional oil and natural gas production. So when we talk about not advancing those projects any further, other than the wavering asset, and the wavering asset will continue on for many, many years to come. And if we can attract more CO2 into that, to replace the voidage there and advance that project, we're going to continue to do so. for a much longer period of time. But developing new carbon capture hubs, that won't be part of our strategy going forward.

Okay, awesome. Sounds like a good spot to be in. I appreciate it, Grant, and everybody else.

Thanks, Michael. And at this time, gentlemen, we have no other questions registered.

Please proceed.

Well, thank you very much, Joanna, and thanks to each of you on the line today and who continue to support us on our journey. We are excited about the opportunities facing our company at this particular time and look forward to updating you on our progress through the balance of 2025 and well into the future. Wish you all the best and enjoy the rest of your summer, sunny summer. Thanks very much.

Thank you, Seth. Ladies and gentlemen, this does include a conclusion conference call for today. Once again, thank you for attending, and at this time, we do ask that you please disconnect.