Whitecap Resources Inc.

Good morning. My name is Sylvie, and I will be your conference operator today. At this time, I would like to welcome everyone to Whitecap Resources' second quarter 2026 results conference call. Please note that all participant lines have been placed on mute 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. And if you would like to withdraw from the question queue, Please press star then number two. I would like to turn the conference over to Whitecaps President and CEO, Mr. Grant Fagerheim. Please go ahead, sir.

Thank you very much, Sylvie, and good morning, everyone, and thank you for joining us here this morning. There are five members of our management team here with us today. Our President, Joey Wong, our Senior Vice President and CFO, Thanh Kang, our Senior Vice President, Asset Development and Information Technology, Dave Mombourquette, and our Vice President, Conventional Division, Reserves and Reservoir Development, Chris Bullin. Before we get started today, I would like to remind everybody that 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. We are once again pleased to report exceptionally strong operational and financial results for the second quarter of 2026. Our technical and operations teams continued to execute effectively across our second quarter capital program, with asset productivity exceeding expectations. Our second quarter funds flow was a big number at $1.4 billion, or $1.11 per share, a record for Whitecap that we are very pleased with. As most are aware, disruptions to crude oil and condensate supply from the Middle East materially heightened Global availability of light barrels during the quarter and is still ongoing, supporting stronger benchmark prices and increased demand for North American light oil and condensate. The combination of crude oil and condensate pricing and continuing to lower operating costs resulted in a robust operating net back of $43.84 for BOE, a 48% improvement to the prior year quarter. Free funds flow of $925 million was also a record for Whitecap. With these incremental funds, we will continue to execute our counter-cyclical approach to free funds flow allocation. During periods of elevated commodity prices, we will prioritize debt reduction, strengthen the balance sheet, and preserve maximum flexibility to enhance shareholder returns across commodity price cycles. Over the last six months, we have reduced our net debt By $900 billion to $2.5 billion, or 0.5 times debt to cash flow. From an operational perspective, Whitecap delivered another strong operating quarter, with production averaging 388,894 BUE per day, comprised of 239,083 barrels of liquids, slightly under 900 billion cubic feet a day of natural gas. We drove 47 wells across the Montney, Duvernay, and our conventional portfolio, using approximately seven rigs during the quarter. With spring break-up now behind us, activity is increasing as planned. We expect to use approximately 12 rigs through the third quarter and into the fourth. Our average quarterly production exceeded our internal forecast by approximately 8,000 BW per day, driven by strong asset-level performance at KBOB, and Base Production Optimization in Central Alberta. More broadly, results were shown across both divisions with new oil performance, base optimization and high infrastructure utilization contributing positively during the quarter. These results reflect consistent application of an integrated development workflow which combines the expertise of our technical and operating teams with a deep proprietary data set and rigorous feedback loops from each well pad and pad drill. Based on this outperformance, we are raising our 2026 production guidance for the second time this year by 5,000 BWE per day to 385,000 BWE per day. This represents a total increase from our original budget guidance of 12,500 BWE per day, or 3%. From a capital spending point of view, we are not making any changes to our 2026 capital Given the shorter cycle times that we're seeing across our asset base, we plan to maintain activity levels and expect to spend at the high end of our capital spending range, guidance range. I will now pass the call over to Tom for further discussion on the second quarter financial results. Tom?

Thanks, Grant. Petroleum and natural gas revenue increased 93% to $2.6 billion, driven by higher crude oil and condensate pricing as a result of the ongoing conflict in the Middle East. as well as the inclusion of a full quarter of production from the Barron assets. Second quarter WTI averaged $92.79 US per barrel while MSW traded at a premium to WTI of $2.52 per barrel and condensate traded as premium to WTI of $2.69 per barrel. Combined with the recent Canadian dollar, this resulted in a realized crude oil and condensate price of Canadian $127.82 In the second quarter, Whitecap produced over 200,000 barrels per day of oil and condensate, with the light oil and condensate volumes realizing a premium to WTI. Total liquids accounted for approximately 93% of our revenue during the quarter, despite being only 61% of total production. April prices remained challenged during the second quarter and were also impacted by unsigned 10G TL maintenance. resulting in ACO prices averaging $1.63 per MCS in the second quarter. The impact of our natural gas price diversification was seen in our realized natural gas price in the second quarter, averaging $2.29 per MCS, or a 66 cent premium to ACO. As Grant mentioned, we continue to improve our cost structure with operating costs at $11.88 per VOE in the quarter, down 13% compared to the prior year quarter. Given this trend, we are reducing our full-year operating cost forecast to $12 per VOE at the midpoint, which is a $0.50 per VOE reduction relative to our original budget, which increases free cash flow by approximately $70 million. Second quarter net income increased 186% compared to the prior year quarter to $890 million, or $0.73 per share. The increase was primarily driven by higher petroleum and natural gas sales, which were partially offset by higher royalties, a lower net gain on commodity contracts, and higher DDMA. In the second quarter, we recorded an unrealized gain on commodity contracts of $282 million compared to an unrealized loss of $509.1 million in the first quarter. These large non-cash movements reflect the change in the mark-to-market values of our commodity contracts resulting from significant volatility Our risk management strategy is to hedge between 25% to 35% of our crude oil and natural gas production on a rolling two-year trailing basis. For the second half of 2026, we've hedged 33% of our net crude oil volumes at an average swap price of approximately $94 Canadian per barrel, and 28% of our net natural gas volumes and an average swap rate of $4 per MCF. For 2027, we have hedged 26% of our net crude oil volumes at an average swap price of $93 Canadian per barrel and 13% of our net natural gas volumes at an average swap price of approximately $3 per MCF. Since closing the Barron transaction, we have reduced net debt by $900 million to $2.5 billion, an amount equivalent to WhiteFap's standalone net debt prior to the transaction, and a significant achievement for our company. As Grant mentioned, we will continue to allocate our pre-funds flow towards the balance sheet, and we'll continue to assess opportunities to enhance shareholder returns in the future. I will now pass it off to Joey for more remarks on our unconventional results.

Thank you. Our unconventional division delivered another solid quarter, driven by continued strength in our Montney and Duvernay development programs. Wells brought on production since the start of the year are performing above our internal expectations on aggregate. We do not expect every well or pad to land exactly on the forecast, but we do expect to forecast aggregate performance reliably, understand the drivers of variability, and use those insights to improve the next development and capital allocation decision. CycleTimes continue to improve and are supported by sustained performance across the key drilling and completion execution metrics we discussed earlier in the year. Meters drilled per day and tons of profit placed per day during completions are now 31% and 13% above historical levels respectively, compared with 27% and 12% disclosed in the first quarter, demonstrating continuous improvement and better capital efficiency. At Latour, construction of the 413 facility is now approximately 90% complete, with cost and schedule remaining on budget, with startup expected in the fourth quarter. Following startup, we will direct a five-well pad and existing area production to the new facility, freeing up capacity in the area to bring on a two-well Rest Haven delineation pad prior to the end of the year. Turning to Carr, both of our initial plug-and-purr pilot pads have now been on production for more than 90 days. As we discussed, frac execution was strong, with more than 95% of each lateral effectively stimulated, and they were done at an approximate $2 million per well cost advantage relative to area single point entry completions. Early time diagnostic data indicates that fracture geometry broadly conforms to our design. Overall deliverability is currently tracking within the range of our internal expectations, and after including the well cost savings, Thank you for joining us. Our third plug-and-perf pilot pad, and refers to Gold Creek, is expected to spud in the coming months. As a reminder, we use plug-and-perf technology exclusively in the Duvernay and across our other Monty assets at Caqua, Musro, and Latour, where production results have been strong. Our measured application of it at Carr and Gold Creek reflect the observed differences in subsurface characteristics and the need to tailor both design and execution accordingly. These pilots will expand our comparative data set and help refine where each completion approach provides the strongest risk-adjusted economic return. At KBOC, our DuVernay asset reached its productive capacity range of 115,000 to 120,000 BOE per day within the second quarter, and we are now very pleased to be forecasting production to average within that range through the third and fourth quarters. Our updated outlook reflects the cumulative benefit of stronger well performance, Shorter cycle times, infrastructure re-bottlenecking, and continued base optimization. As KBOB moves into this stable, productive range, our focus is shifting from growth towards sustaining the asset at capacity and harvesting free cash flow from our identified 700 inventory locations. On our updated forecast, KBOB is capable of generating between $800 million and $900 million of annual operating free cash flow at between $70 and $80 WTI. With that, I'll now turn it over to Chris to discuss our conventional assets.

Thanks, Joey. Our high-margin 80% liquids-weighted conventional division was well-positioned to capitalize on strong oil prices during the second quarter. These core cash flow-generating assets continue to deliver substantial returns, contributing almost 45% of operating cash flow while only accounting for 22% of capital spending through the first six months of the year. In our Alberta conventional assets, We continue to realize the benefits of our interconnected infrastructure portfolio as the team successfully redirected portions of a planned third-party turnaround to mitigate the production impact of downtime for the quarter. In addition, we continue to advance base optimization initiatives in the Glauconite by leveraging incremental third-party capacity, which is now expected to remain available through the balance of the year. These efforts, coupled with continued strong asset performance across our Alberta Conventional Region, contributed to the production uplift during the quarter. Shared workflows and technical learnings across the business are improving capital efficiency and performance across our conventional assets. One area where we have recently achieved a step change in results is the Charlie Lake. Our three-well Charlie Lake winter drilling program at Valhalla is significantly outperforming offset wells over the first 90 days. Updated FRAC modeling suggested that a higher crop and intensity would result in increased conductive area and improved reservoir contact through the stacked trellis zones, leading to better well deliverability. This three-well program was completed with approximately double the intensity of previous programs and equipped with higher capacity artificial lifts to accommodate the increased fluid production expected from the FRAC optimization. These early time results suggest an overall improvement in capital efficiency as the higher rates more than offset the increase in costs. We will continue to monitor production performance as additional data becomes available, but the early-time results are encouraging and reinforce our optimism for the updated BRAC technique and its application in future tri-league development. Moving over to Saskatchewan, our assets continue to deliver strong base production performance, particularly across our EOR assets in the Bakken and southwest Saskatchewan, driven by disciplined water flood management and proactive field surveillance. These ongoing optimization initiatives continue to enhance base production and unlock incremental value from our existing asset base with minimal capital invested. We recently completed a full review of the Bakken multi-stage frac inventory, focusing on consolidating one-mile inventory into two-mile inventory, improving its competitiveness and enhancing economics. In parallel, the team is challenging current drilling and completion practices and, in some areas, looking to transition towards a monobore well design. Again, with the ultimate goal to improve capital efficiency across our assets. With that, I'll turn it back over to Grant for his closing remarks.

Thanks, Talon, Joey, Chris, for your comments. The increased focus on energy security and reliability has reinforced the importance of secure, responsibly produced energy. Canada has abundant natural resources and the ability to play a meaningful role in supplying crude oil and natural gas to both domestic and international markets. Thank you very much. Our portfolio includes approximately 10,500 drilling locations across white oil, condensate-rich, liquid-rich natural gas, and lean natural gas assets, providing decades of growth opportunities and significant possibilities to respond to changing commodity prices and market conditions. It has been just over a year since we completed the Barron transaction on May 12, 2025, and the combination is delivering measurable improvements across the asset base. Since closing, capital efficiency has improved by approximately 12%, from $21,000 per flowing BOE to $18,500 per flowing BOE, while operating costs have declined by approximately 13%, from $13.50 on a culmination basis to below $12 per BOE. These improvements demonstrate the benefits of applying Whitecap's operating practices, technical expertise, and capital discipline across our expanded portfolio. A key strength of our portfolio is its exposure to light oil and condensate, which command the strongest realized prices across our product mix in the current commodity price environment and longer term. Combined with lower costs and improved capital efficiency, this exposure supports attractive operating netbacks, strong margins, and sustainable free-form flow. The outlet for Western Canada light oil and condensate remains very constructive. Expanded export capacity and growing demand for secure North American energy supply are expected to support market access and pricing for Canadian light oil. As one of the largest light oil and condensate producers in Western Canada at approximately 120,000 barrels per day, White Tap has significant exposure to these market fundamentals and a deep, long-duration inventory of light oil drilling opportunities. Recently announced oil pipeline expansions Thank you very much. Whitecap has delivered an 11% compound annual growth rate in production per share, well above the long-term annual growth rate of 3-5% while maintaining prudent debt levels. Whitecap has the inventory depth, premium product exposure, financial strength, and strong technical capabilities to generate sustainable shareholder returns and capitalize on the growing demand for secure Canadian energy. With that, I will now turn the Thank you, sir.

Ladies and gentlemen, if you do have any questions, please press star followed by one on your touchstone 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're using a speakerphone to please lift the handset first before pressing any keys. Please go ahead and press star one now if you have any questions. Travis Woods at National Bank.

How should we be thinking about the growth through the rest of this year? Grant, you did a good rundown on the efficiencies since the Varon transaction. So how should we start to manage this in terms of, is this all better well results, drilling efficiencies, or is this timing related, just as I'm looking at? Yeah, I'll take a first crack at that, Travis. So, I think when we look at the outperformance, it's basically 50-50 in terms of where it's coming from, the conventional and the unconventional assets.

I'd say that 55% of that, you know, 8,000 VUEs per day of outperformance, was driven by new production and the performance of the new wells, and then 45% on base level optimizations. As we think about the production cadence for the rest of the year, keep in mind in Q3 we still have 10,000 DOEs per day of downtime that we've incorporated in our guidance. With the view that we're going to be exiting in excess of 385,000 VOEs per day this year here. So we were able to uplift the back half of 2026 here by about 5,000 VOEs per day. You see that reflected in the upward revisions to our guidance there. As we look at the business on a go-forward basis, as Grant talked about there, the objective here is to grow 3% to 5% on a per share basis. And our base case for next year in 2027 is this 3% growth. But we can continue to evaluate that as we execute, you know, on our program for the rest of the year here.

Okay. No, that makes sense. So it's kind of staying with the plan and in the interim getting the upside from the operating side. So maybe the follow-up to that is, Since integrating, and now you're fully integrated from the inventory side, as you look across the areas, both Joey and Chris did a good rundown on their segments, are there any areas of surprise that's outperforming your expectations from the inventory side and forcing you to look to allocate more capital than you originally planned into those assets, both on the Chris talked about the Charlie Lake as an example. So how is that integration now looking a year out since original expectations on an asset base?

I appreciate the question there, Travis. I can take that one. I'd say that pretty consistent with what Grant said in the prepared remarks there, that the results and the beats have been pretty broad-based when you look at both the inputs, so the rate at which we're able to, like I noted there, drill and complete the wells, and of course the associated capital savings that come along with that, but then The resulting production across the board has been on aggregate beating expectations. So I would say that if we're trying to focus on one area of surprise, it's not necessarily that there's been one area, whether that's on the legacy Whitecap or the legacy Varon. It's been broad, like I say. And it comes as a result of the integrated development workflow we talk about. And Chris spoke to that about how plays like the Charlie there, which is a legacy Whitecap play, Still seeing improvements on that play by looking to the fundamentals of the design bases that we have, trying to figure out how we can optimize those and continue to turn out new results. So ultimately, at the end of the day, does it mean that there's a tendency to want to, to your question, to lean into any area more than another? The answer is not in any specific terms, but we'll just continue to do what's been working well for us, which is that continuous workflow and Making everything better along the way. Anything else there, Chris?

No, I think you hit it there, Joey, for sure. And I mean, specifically on the conventional side, I mean, I think it's just great to see that we continue to drive forward with it. You know, I'll just speak to the workflows a bit there. Just, you know, going through that methodical process, trying to better understand from a modeling perspective if we can incorporate, you know, different variations in crack design and You know, seeing the output and watching this come through in the last three wells that we had talked about there, I think that's great to see. And our teams aren't going to stop there. I mean, we'll keep looking at different iterations and keep finding ways to enhance, you know, completion optimizations, particularly on the Charlie.

Okay. Perfect. And appreciate that from everybody. And then my point five of the question is, if you can humor me, So with the KBOB DuVernay now at capacity, are there any kind of medium-term plans to look to expand processing capacity there, or will that kind of fall after Latorre comes on stream?

We've got a list of opportunities, Travis. That's a full question. I don't know if that's an ask. But anyway, we've got a list of opportunities that we can look to for expanded capacity. It probably works well reminding here that as it stands right now, we have 80,000, including Latour, we have 80,000 BOEs per day of capacity available to us to grow into. So to think about expanding that, we would then need to look at the overall all-in economics of the expansion and then the associated development to go back in and fill that. And that's why we kind of said, you know, Thank you very much. Thank you. Next question will be from Michael Harvey at RBC. Please go ahead, Michael. Yeah, sure. Good morning.

A couple questions for me. I guess maybe for Thanh, lots of free cash flow generated, but really no buybacks so far this year. So maybe just walk us through how you're weighing allocating free cash to debt versus the buybacks and kind of what we can expect for the balance of the year. And also just if that's being impacted by other strategic priorities like M&A, keeping dry powder, etc., And then second one, maybe for Joey, and just kind of tying into Travis's question, you mentioned that outperformance in the DuVernay. We can see it in the public data, too. Just wondering if you can share some of the wins there in terms of drilling completions and anything new that might be helping to drive that. Thanks.

Yeah, thanks for those questions there, Michael. I'll take the first one there. Yeah, we're going to continue with our counter cyclical approach to free cash flow allocation in this pricing environment here where crude oil prices are elevated due to the conflict in the Middle East. So what that will provide us is really maximum optionality to deploy those funds in the future, whether it's on dividends, share buybacks, or smaller tuck-in acquisitions right within the core areas. And we can make that determination at a future point in time What I will say, though, is it doesn't preclude us from buying back shares in the back half of 2026 here. I mean, management has been buying at these levels in the market. And I think we have to keep in mind that only 30% of our reserves is booked in our reserve report at this time. So there's significant unbooked value for future net asset growth as we think about the business here. But consistent with what we've been communicating is, well, continue with our countercyclical approach and prioritize the balance sheet at this time.

Yeah, Michael, on your second question there on the DuVernay, I think it's a mix. On the new developments, it's a mix of design and execution. So on the design side, we've spoken at relative length to some of the design changes we've made with respect to how we land the wells vertically, the wind racking we've spoken to. That's still yielding repeatable and some pretty impressive results. We disclosed 10 to 20% improvement and that's still being realized where we're doing that. Also looking at adjusting spacing, drawdown targets, all of those things that go into the inputs. But then importantly as well on the execution side, Travis and his team, when we execute these wells utilizing the centralized draft room that we have, ensuring that we're stimulating the entire lateral and not leaving anything behind and sweeping the entirety of the reservoir that we're covering. So it's a combination of all those things that are coming together on the growth side, but I'll also say those on the optimization of the base. The base optimization benefited from basically a couple of things. The ability for us to use our operating practices to keep up with Thank you for joining us. One of the benefits of having an established asset base in core areas is that we have those degrees of flexibility to be able to navigate and, like I say, not be unduly impacted when we bring new production on.

Great. Thanks, guys.

Next question will be from Jeremy McCray at BMO Capital Markets. Please go ahead, Jeremy.

Hi, guys. A couple of questions here as well, too, and a bit of follow-up to Mike here. So you look into next year, you have a lot of free cash, a lot of the debt has been paid down. What do you start to think about in terms of where you might allocate that capital? Is it back to more aggressive buybacks or is it more growth? And just more thinking about how you bring the 40 years of inventory forward here a little bit more.

Yeah, thanks, Jeremy. Just regarding this year, we're in the planning process for 2027 and the next three- to five-year period of time. Right now, as far as the – as Tawana referenced earlier about the maximum optionality, when we have lower levels of debt that we continue to focus on, you know, dividend payments, whether it's enhancing the dividend, share buybacks, additional small-scale or large-scale M&A payments, will be on the docket, as well as increasing the opportunity to increase our capital program for higher-end growth. We talk about 3% to 5% per share growth, 3% at the minimum, 5% at the higher side, but it allows us that full flexibility. We live in a very unstable world at this particular time, so oil prices, as Tana referenced earlier on, We've got 61% of our production at this particular time generating 93% of our revenue. So with these elevated oil prices, are they elevated? We'll see if they're elevated. We think they are. And could this go for an extended period of time? So it has to go back to, we have to think about it in that context. And when we're trying to develop as much shareholder value as we can, we have to think about what's the longer term outlook of commodity prices, both on crude oil, the weaker Canadian dollar, and Natural crude oil and condensate pricing. And the demand, we're building demand with the build-out of the oil sands projects that we're supportive of. That requires condensate. So there needs much more condensate if we're going to grow our heavy oil volumes by a million to two million barrels a day. That's an incremental 300,000 to 500,000 BW per day of condensate demand as well. So those are all the backdrops. It's not just one solution. We have to look at it holistically from many different components. Anything else to add, Tony?

Yeah, I'd say that as we look at 2027 from a mid-cycle pricing perspective, we'll call that $65 to $75 WTI. We've got the ability to continue to grow in that 3% to 5% range there. The dividend, very comfortable with it, but longer term. We do want to grow our dividend as well. So we're growing our production and our cash flow by 3% to 5%. We want to continue to grow that dividend and that 1% to 2% on a long-term basis there. And we still have enough free cash flow to continue to buy back our shares in that 2% to 4%. So I think when we think about that pricing dynamic potential in 2027, We can grow, we can support the dividend and increase it with the increasing cash flows that we're generating, and we can continue to buy back our shares in that 2% to 4%. And at the same time, as we look at our debt at the end of this 2026 year, it's going to be closer to $2 billion is what we're anticipating. And so, as we continue to execute in 2027, leverage still remains in that $2 billion range there. We're very optimistic about not only this year, but the setup for 2027 as well in terms of that return of capital to our shareholders.

Okay, appreciate that. Then maybe just a quick follow-up here. A lot of other companies have talked about, you know, using wet sand and, you know, these lightweight propants here that have really improved some of their Permian results. I know you guys... really are in the forefront of new technology and that's why we've seen the year capital efficiency improvements. Is there any contemplation of using some of these newest US designs and technology up here in Canada?

Jeremy, this is Travis Tweit. Yeah, with FAN being about one of the largest input costs for a capital program, it's something we're looking at all the time. We're very comfortable with the operations. We're comfortable with the logistics, and we see the efficiency and the cost-benefit going forward.

Perfect. Appreciate that, Travis. Thank you.

Next question will be from Aaron Wilkowski at TD Cowan. Please go ahead, Aaron.

Thanks. Good morning. I'm going to ask a higher-level question that really ties to some of Grant's closing comments. On the large-cap and mid-stream conference calls, there's been a fair amount of discussion about future condensate supply, obviously in context of the recent pipeline MOU. Can you guys talk a little bit about how you see WhiteCast's role in meeting growing demand for diluent over the next five years and maybe take that a step further? How much condensate could you reasonably add over that period?

Yeah. Thanks, Aaron. Grant here. And just, you know, I think one of the things that we have to, that, Our federal government policies, we're acknowledging and committing the need to put our competitive policy and regulation framework in place to support meaningful growth from Canadian projects. So I think that backdrop, if that continues to hold and actually comes into execution versus just terminology, we're very excited about that. And this is where I think Canada, this is a time for us to Canada to stand forward on our energy development platforms We talk about, it's not just the, we'll call it the oil sands, the projects that can grow in Canada. We have a significant amount of natural gas. We have a significant amount of light oil that can grow in our inner. So where we come back to light oil and condensate, we talk about to close the circle on growth for oil sands, that is going to require condensate. So at this particular time, we talk about having approximately 60,000 BW per day. Could we increase that, you know, maybe by somewhere between 25,000 to 50,000 BW per day increase as we advance through time with our portfolio of opportunities? Yes, we can. So, you know, we're building, Canada is building its own demand for its product. If we're going to actually grow the oil sands projects, we're consistent with that. We want to grow our light oil, condensate, and Natural Gas Portfolio as well. The challenge we've had with natural gas is that the demand in North America has been weak. But with data center development and some of the things we're doing with developing, if the pathways group continue or now get on their front foot to grow, they're going to need more natural gas as well. So I think that... All in, all encompassing, we are producing about just shy of 990 of natural gas, and we have lots of growth on natural gas as well. So light oil, condensate, and natural gas opportunities for growth, I think will continue to remain our drivers as we advance forward.

Maybe I can add on that, too, is when you look at our unconventional asset base, we've got 4,700 identified inventory locations, 70% of them are within the liquids or condensate window that Grant talks about there. So Latour is condensate rich. So we've got the ability to grow within that asset base that we currently are working with at this time.

Thank you. Next question will be from Phillips Johnston at Capital One. Please go ahead, Phillips.

Hey guys, thanks for the time. Just a couple of housekeeping questions for me on the modeling front. First on CapEx, I guess we're tracking to a figure close to the high energy guidance range given the compressed cycle times that you noted. That implies around a billion dollars or so for the rest of the year. I recall that third quarter CapEx is expected to be higher than Q4, but you maybe help us with the split for those two quarters. Should we model something around 50%, 40% or so?

Yeah, it's time here. Typically, you know, you'll see the cadence of capital being, you know, highest in the first quarter, and then with break-up, it's a little bit lighter in the second quarter. Very similar in the back half of the year here. You know, our CapEx spending will be somewhere in that $600 million in Q3, and then it'll be about $400 million in the fourth quarter to get us to that $2.1 billion on an annual basis.

Okay, perfect. And then you guys have earned your current income tax expense guidance of 68% of funds flow. I know it's early to talk about 27, but just for modeling purposes, what sort of placeholder would you recommend that we use just assuming current stroke prices hold?

Yeah, it's really going to depend on commodity prices. I think the back half of this year, 7% to 8% at the end of the second quarter, Thank you. As a reminder, ladies and gentlemen, if you do have any questions, please press star followed by one on your touchtone phone. Thank you.

Next question will be from Dennis Fung at CIBC. Please go ahead, Dennis.

Good morning, and thanks for taking my questions. My first one here is you've been doing, obviously, great job optimizing, as we see from the prepared comments as well as the work that you did at KBOG, again, as you had mentioned. And then with Latorre effectively at 90% completion here, How do you think about advancing some of these future growth potential projects? So things like Latour Phase 2, the Gold Creek or car expansion, or the CACO expansion as you highlighted at your investor day. Just as we think about the next leg of growth, How do you think about balancing kind of moving forward with a larger scale project as well as like balancing production ramp up from existing facilities optimization as well as a transition towards kind of each one of those individual previous projects transitioning to like a free cash flow generating asset?

Yeah, good question, Dennis. Appreciate that and appreciate you identifying that. Exactly that. You know, we have this wealth of opportunity with which to be able to grow into either in the existing capacity we spoke about there earlier or with legs of growth, either a bolt-on Latour Phase 2 or other things there. In a word, I would say the decision has to be holistic. We have to look at What the underlying strength of the inventory is, and again, it's pretty widespread. We also have to look at what the forward-looking quantity prices are looking like and what we want to do corporately in terms of dispatching growth of different characteristics. So when you look at the asset base, because of the fact that we have this wide variety between the oil and condensate, like I mentioned there, earlier or down into the gas. Should there be a call on gas many years down the road, however many that's going to be, we're able to make that decision as it presents itself at the time. But coming back to the word there that I said, it'll be holistic. We'll look at the inventory, we'll look at the build-out cost, and we'll look at the all-in capital returns associated with it, and they call from there. But there's repeating, like I said, in the K-Lob expansion commentary. We've got a fair amount to work with in the near term.

Great. Great. I appreciate that. And then maybe this is a bit of a follow-up to that first question and kind of continuing around the thought process around growth. I know historically you've talked about managing kind of three, we'll call it pillars, associated with a strong business model in terms of managing decline rate, maximizing net back, and improving capital efficiencies. It's clear just with the upward revisions on guidance that you've been doing a really good job on the capital efficiency side. I'm just curious, if you're continuing to focus on growth on a go-forward basis and obviously managing the balance sheet in terms of your free cash allocation, how do you think about the decline rate component of that three-pillar view of managing the business? And how does that, again... Thank you. Thank you. Thank you.

and a high amount of growth that would lead to an undue impact on our decline rate. And at the same time, of course, the portfolio that we have, and this is, of course, very much by design, is this balance between conventional and unconventional, and on the conventional side still having the benefit of the support of all the water flood and EUR initiatives that we continue to support. And maybe I'll pass it over to Chris for some thoughts on that.

Yeah, for sure. You know, we do continue to support those. I mean, we look at that very much as a sustainability-driven initiative. You know, when you look at the conventional portfolio in particular, I mean, our sub-20% decline, of course, is supported by 52,000 barrels a day of dedicated water plus EOR production. And we continue to fund that. We continue to optimize it, as we had mentioned, you know, as part of the base optimization initiatives at the onset. Our teams are doing a great job continuing to push that forward. I mean, in Saskatchewan, there's a lot of examples of that. You know, older legacy place, of course, being the Bakken and Southwest Sask. But, you know, we continue to benefit, I would say, from, you know, very disciplined and proactive water flood management, you know, coupled with a formal reservoir management process. And our teams are doing a great job both in the field and in the office. They're armed with a variety of different surveillance tools, of course, to help continue to bolster that. And we're starting to see the results of that. So for us, I mean, it's an important part of, you know, continued decline mitigation. We continue to fund it. Those projects screen very favorably from a capital economics perspective, in particular from an optimization perspective. We have a lot of examples of that, you know, just base optimization. Those will be some of our strongest capital efficiencies. You know, whether it's injector conversion optimizations, sweep efficiency, just a variety of different flood optimizations. So, we continue to focus, you know, our field and production optimization teams on that in conjunction with supported, you know, drilling growth to selective areas such as the Bakken, Cardium. I mean, those are also water flow supported areas. that we continue to drill and benefit from, you know, pressure response there. So, it helps to bolster our volumes there compared to primary. So, yeah, something we continue to fund and look at very actively.

Great. Thanks, Joey and Chris. I really appreciate the context there.

Thank you. At this time, I would like to turn the conference back over to Mr. Fagerheim.

Thank you, Sylvia, and thanks to each of you online today. who continue to support our story and our team. From our entire management team, I want to once again thank our entire Whitecap staff and contractors for your dedication and efforts on delivering a very strong quarter on a continuation from what we've had over the last one-year period of time. We look forward to updating you on our progress through the remainder of the year and into the future. All the best to each of you. Enjoy your summer. Signing off for now. Cheers.

Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. At this time, we ask that you please disconnect your lines. Enjoy the rest of your day.