Whitecap Resources Aktie

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. [Operator Instructions]. I would like to turn the conference over to Whitecap's President and CEO, Mr. Grant Fagerheim. Please go ahead, sir.

Thanks very much, Sylvie, and good morning, everyone, and thank you for joining us here this morning. There are 5 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; our Chief Operating Officer, Travis Tweit; 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 continue 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 materiality -- materially tightened 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 netback of $43.84 per 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 countercyclical 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 6 months, we've reduced our net debt by $900 million to $2.5 billion or 0.5x debt to cash flow. From an operational perspective, Whitecap delivered another strong operating quarter with production averaging 388,894 BOE per day, comprised of 239,083 barrels of liquids, slightly under 900 million cubic feet a day of natural gas. We drilled 47 wells across the Montney, Duvernay and our conventional portfolio using approximately 7 rigs during the quarter.

With Spring breakup 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 BOE per day, driven by strong asset level performance at Kaybob and base production optimization in Central Alberta.

More broadly, results were strong across both divisions with new well performance, base optimization and high infrastructure utilization contributing positively during the quarter. These results reflect consistent application of integrated development workflow, which combines the expertise of our technical and operating teams with a deep proprietary dataset and rigorous feedback loops from each well pad and pad drilled.

Based on this outperformance, we are raising our 2026 production guidance for the second time this year by 5,000 BOE per day to 385,000 BOE per day. This represents a total increase from our original budget guidance of 12,500 BOE per day or 3%. From a capital spending point of view, we are not making any changes to our 2026 capital spending guidance of $2 billion to $2.1 billion.

Having said that, 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 on to Thanh for further discussion on our second quarter financial results. Thanh?

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 Veren assets. Second quarter WTI averaged USD 92.79 per barrel, while MSW traded at a premium to WTI of $2.52 per barrel and condensate traded at a premium to WTI of $2.69 per barrel. Combined with a weaker Canadian dollar, this resulted in a realized crude oil and condensate price of CAD 127.82 per barrel. In the second quarter, Whitecap produced over 200,000 barrels per day of oil and condensate with 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. AECO prices remained challenged during the second quarter and were also impacted by unplanned NGTL maintenance, resulting in AECO prices averaging $1.63 per Mcf 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 Mcf or a $0.66 premium to AECO. As Grant mentioned, we continue to improve our cost structure with operating costs at $11.88 per BOE in the quarter, down 13% compared to the prior quarter -- prior year quarter.

Given this trend, we are reducing our full year operating cost forecast to $12 per BOE at the midpoint, which is a $0.50 per BOE 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 DD&A.

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 noncash movements reflect the change in the mark-to-market values of our commodity contracts resulting from significant volatility in crude oil prices.

Our risk management strategy is to hedge between 25% to 35% of our crude oil and natural gas production on a rolling 2-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 CAD 94 per barrel and 28% of our net natural gas volumes at an average swap price of $4 per Mcf. For 2027, we have hedged 26% of our net crude oil volumes at an average swap price of CAD 93 per barrel and 13% of our net natural gas volumes at an average swap price of approximately $3 per Mcf.

Since closing the Veren transaction, we have reduced net debt by $900 million to $2.5 billion, an amount equivalent to Whitecap's stand-alone net debt prior to the transaction and a significant achievement for our company. As Grant mentioned, we will continue to allocate our free 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.

Thanks, Thanh. 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.

Cycle times continue to improve and are supported by sustained performance across the key drilling and completion execution metrics we discussed earlier in the year. Meters per day and -- meters drilled per day and tonnes of proppant placed per day during completions are now 31% and 13% above historical levels, respectively, compared with 27% and 12% as disclosed in the first quarter, demonstrating continuous improvement and better capital efficiency.

At Lator, construction of the 04-13 facility is now approximately 90% complete with cost and schedule remaining on budget with start-up expected in the first -- in the fourth quarter. Following start-up, we will direct a 5-well pad and existing area production to the new facility, freeing up capacity in the area to bring on a 2-well Resthaven delineation pad prior to the end of the year.

Turning to 21:31 Karr. Both of our initial plug-and-perf 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 conformed to our design. Overall deliverability is currently tracking within the range of our external -- internal expectations. And after including the well cost savings, pad level capital efficiency is forecasted to be better.

In parallel, our teams have demonstrated improvements on single-point entry completion execution in Gold Creek as compared to legacy completions, which have improved by approximately 23% on a tonnes per day basis compared with the 13% improvement across our broader Unconventional program I mentioned earlier. This has narrowed the expected plug-and-perf cost advantage in the Gold Creek area from approximately $1 million to roughly $750,000 per well. Our third plug-and-perf pilot pad and our first 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 Montney assets at Kakwa, Musreau and Lator, where production results have been strong.

Our measured application of it at Karr 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 Kaybob, 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 debottlenecking and continued base optimization.

As Kaybob 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, Kaybob 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 6 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 3-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 proppant intensity would result in increased conductive area and improved reservoir contact through the stacked Charlie Lake zones, leading to better well deliverability. This 3-well program was completed with approximately double the intensity of previous programs and equipped with higher capacity artificial lift 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 frac technique and its application in future Charlie Lake 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 waterflood 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 multistage frac inventory, focusing on consolidating 1-mile inventory into 2-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, Thanh, Joey and 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 that we do not share the same advantages as Canada has. Other markets do not share the same advantages Canada has. Continued progress on competitive regulations and policies is required to strengthen market access and establish Canada as a reliable long-term supplier of energy to customers at home and around the world.

Whitecap is well positioned to participate in the growing demand for responsibly produced energy. Our portfolio includes approximately 10,500 drilling locations across light oil, condensate-rich, liquids-rich natural gas and lean natural gas assets, providing decades of growth opportunities and significant flexibility to respond to changing commodity prices and market conditions.

It has been just over a year since we completed the Veren 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 combination 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 funds flow.

The outlook 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, Whitecap has significant exposure to these market fundamentals and a deep long-duration inventory of light oil drilling opportunities.

Recently announced oil pipeline expansions are also expected to increase heavy oil transportation capacity and in turn, the volume of condensate required as diluent. As the fourth largest condensate producer in Western Canada of approximately 60,000 BOE per day, Whitecap has a substantial inventory of condensate-rich drilling location positioned to benefit from the incremental demand.

Our performance over the past 5 years demonstrates our ability to convert asset quality and disciplined execution into shareholder value. Over that period, Whitecap has delivered an 11% compound annual growth rate in production per share, well above the long-term annual growth rate of 3% to 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 secured Canadian energy.

With that, I will now turn the call over to operator, Sylvie, for any questions.

[Operator Instructions] First, we will hear from Travis Wood at National Bank.

I kind of have 2.5 questions here maybe. All right. We've been through a few quarters of some pretty strong production beats. You've been holding capital flat. This is the second raise on guidance. Maybe could you talk to -- and maybe this goes back to Joey and Chris or maybe Thanh can navigate this.

But 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 Veren 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 the revised guidance given where Q2 volumes are, it still seems like you could beat that again. So just trying to manage that through the year. And then I'll have one follow-up for you.

Yes. I'll take a first crack at that, Travis. So I think when we look at the outperformance, it was basically 50-50 in terms of where it's coming from the Conventional and the Unconventional assets. I'd say that 55% of that 8,000 BOEs 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 BOEs 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 BOEs per day this year here.

So we were able to uplift the back half of 2026 here by about 5,000 BOEs per day, and 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 still to grow 3% to 5% on a per share basis. And our base case for next year in 2027 is 3% growth. But we can continue to evaluate that as we execute on our program for the rest of the year here.

Okay. No, that makes sense. So kind of staying with the plan and the interim getting -- seeing the upside from the operating side. So maybe the follow-up to that is since integrating and now you're probably fully integrated from the inventory side, as you look across the areas, both Joey and Chris did a good rundown on their kind of segments. Are there any areas of surprise that's outperforming your expectations from the inventory side and kind of 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 the 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 Veren. -- it's been broad, like I say there. 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 Lake, which is a legacy Whitecap play, still seeing improvements on that play by looking to the fundamentals of the design basis 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 is a tendency to want to -- to your question there 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 enhanced innovation on generally more mature assets. I think Charlie Lake is a really good example of that. Want to speak to the workflows a bit there, just going through that methodical process, trying to better understand from a modeling perspective, if we can incorporate different variations in frac design and seeing the output and watching this come through in the last 3 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 completion optimizations, in particular on the Charlie side.

Perfect. And I appreciate that from everybody. And then my point 5 of the question is, if you can humor me, is -- so with the Kaybob 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 Lator comes on stream?

Yes. We've got a list of opportunities, Travis. That's a full question. I don't know if that's asked. But anyway, we got a list of opportunities that we can look to for expanded capacity, but probably worthwhile reminding here that as it stands right now, we have 80,000 -- including Lator, 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've kind of said this 115,000 to 120,000 BOE per day range is a nice place to be in the context of what we've been able to do from a debottlenecking perspective in the first place.

So I know that's a nonanswer there, but what I would suggest is, yes, we'll look to fill what we can in large part. And then yes, if there are little things that crop up a little debottlenecking opportunities, like I'm talking in the range of single-digit thousands of BOEs per day, yes, we'd probably jump all over that. But in terms of a material leg of growth, probably wouldn't be looking to do that at least in the near term.

Next question will be from Michael Harvey at RBC.

Yes. A couple of 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, et cetera?

And then second one, maybe for Joey and just kind of tying into Travis' 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 just in terms of drilling and completions and anything new that might be helping to drive that?

Yes. Thanks for those questions, Michael. I'll take the first one there. Yes, we're going to continue with our countercyclical 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 our 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 we'll continue with our countercyclical approach and prioritize the balance sheet at this time.

Yes, Michael, on your second question there on the Duvernay, it's a mix. On the new development, 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 made with respect to how we land the wells vertically. The wine 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 frac 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.

And 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 artificial lift needs and optimization opportunities on existing things.

But in addition to that, the way we've deployed our capital now that we've combined the 2 assets and the way that we can direct flows allows us to optimize the flowing conditions of these wells. So we can take advantage of this larger footprint to be able to keep that base sustained and it doesn't feel undue pressure from new development. And you see that here in the Duvernay. It's also something that Chris mentioned in Central Alberta. This is 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.

Next question will be from Jeremy McCrea at BMO Capital Markets.

A couple of questions here as well, too, and a bit of a follow-up to Mike here. So you look into next year, you have a lot of free cash flow. 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.

Yes. Thanks, Jeremy. Just regarding next year, we're in the planning process for 2027 in the next 3- to 5-year period of time right now. As far as the -- as Thanh had referenced earlier about the maximum optionality, when we have lower levels of debt that we continue to focus on dividend payments, whether it's enhancing the dividend, share buybacks, additional small-scale or large-scale M&A, we will be on the docket as well as increasing our -- the opportunity to increase our capital program for higher end of growth.

We talked about 3% to 5% per share growth, 3% at the minimum, 5% at the higher side. But it allows us that full flexibility. These we live in the world that -- a very unstable world at this particular time. So oil prices, as Thanh 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. But -- and could this go for an extended period of time. So it has to go back to -- we have to think about in that context 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 1 million to 2 million barrels a day. That's an incremental 300,000 to 500,000 BOE per day of condensate demand as well. So those are all the backdrop. It's not just one solution, we have to look at it holistically from many different components. Anything else to add, Thanh?

Yes. I'd say that as we look at 2027 from a mid-cycle pricing perspective, call that $65 to $75 WTI, we've got the ability to continue to grow in that 3% to 5% range there. The dividend, we are comfortable with it. But longer term, we do want to grow our dividend as well. So if we're growing our production and our cash flow by 3% to 5%, we want to continue to grow that dividend in 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 2026 here, 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. So 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. I appreciate that. And then maybe just a quick follow-up here. A lot of other companies have talked about using wet sand and these lightweight proppants 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 your capital efficiency improvements. But is there any contemplation of using some of these newest U.S. designs and technology up here in Canada?

Jeremy, this is Travis Tweit. With sand being about one of the largest input costs to our capital program, it's something we're looking at all the time. Currently, with respect to wet sand, we have met with some of the Permian operators. We have gone down, seen their operations, we have talked to multiple mine operators and sand logistics companies. Although we have not found any yet, we're very comfortable with the operations. We're comfortable with the logistics, and we see the efficiency and the cost benefit going forward.

Next question will be from Aaron Bilkoski at TD Cowen..

I'm going to ask a higher-level question that really ties to some of Grant's closing comments. On the large cap and midstream 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 Whitecap's role in meeting growing demand for diluent over the next 5 years? And maybe take that a step further, how much could you reasonably add over that period?

Yes. Thanks, Aaron. It's Grant here. And just -- I think one of the things that we have to -- that our federal government policies we're acknowledging and committing the need to put a 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 -- really 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 that we do have.

We talk about -- it's not just the -- we'll call it, the oil sands 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 -- so where we come back to light oil and condensate, and 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 BOE per day. Could we increase that maybe by somewhere between 25,000 to 50,000 BOE per day increase as we advance through time with our portfolio of opportunities? Yes, we can.

So we're building -- Canada is building its own demand for its product. If we're going to actually grow the oil sands projects, we consistent with that want to grow our light oil condensate and natural gas portfolio as well. As you know, 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 the Pathways group, the continue to 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 900 million a day 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-rich or oil condensate window that Grant talks about there. So Lator is condensate rich. So we've got the ability to grow within that asset base that we currently are working with at this time.

Next question will be from Phillips Johnston at Capital One.

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 end of your guidance range given the compressed cycle times that you noted. That implies around $1 billion or so for the rest of the year. I recall that third quarter CapEx is expected to be higher than Q4, but can you maybe help us with the split for those 2 quarters? Should we model something around 60%, 40% or so?

Yes, it's Thanh here. Typically, you'll see the cadence of capital being highest in the first quarter and then with breakup, it's a little bit lighter in the second quarter. Very similar in the back half of the year here. Our CapEx spending will be somewhere in that $600 million in Q3, and then it will 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 affirmed your current income tax expense guidance of 6% to 8% 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 strip prices hold?

Yes. 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, we've got $9 billion of tax pools that are available to us. So it will really depend on what the commodity price looks like next year, but we've got some really good tax coverage here. So I think 2027, probably too early to talk about at this time.

[Operator Instructions]

Next question will be from Dennis Fong at CIBC.

My first one here is you've been doing obviously a great job optimizing as we see from the prepared comments as well as the work that you did at Kaybob, again, as you had mentioned. And then with Lator effectively at 90% completion here, how do you think about advancing some of these future growth potential projects?

So things like Lator Phase 2, the Gold Creek or Karr expansion or the Kakwa 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.

Yes. Good question, Dennis. I appreciate that. And I appreciate you identifying that -- exactly that. 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 Lator Phase 2 or other things there.

And in a word, I would say the decision has to be holding. 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 commodity 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 is it will be holistic. We'll look at the inventory. We'll look at the build-out costs, and we'll look at the all-in capital returns associated with it and make a call from there. But bears repeating, like I said in the Kaybob 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 is, I know historically, you've talked about managing kind of 3, we'll call it, pillars associated with a strong business model in terms of managing decline rate, maximizing netback 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 like 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 3-pillar view of managing the business? And how does that, again, consider -- or how is that considered on a strategic basis as you go forward?

I can start there and maybe pass to Chris for his thoughts on the Conventional side there. But short answer is between the 3% to 5% growth target that we have, we don't see a lot of pressure on the decline rate. But one of the many inputs that feeds into that is that isn't a high amount of growth that would lead to an undue impact on 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 waterflood and EOR initiatives that we continue to support. And maybe that's -- I'll pass it over to Chris for some thoughts on that.

Yes, for sure. We do continue to support those. I mean we look at that very much as a sustainability-driven initiative. 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 waterflood plus EOR production. And we continue to fund that. We continue to optimize it, as we had mentioned, as part of the base optimization initiatives on 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, older legacy plays, of course, being the Bakken and Southwest Sask. But we continue to benefit, I would say, from very disciplined and proactive waterflood management, 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 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. Just base optimization, those will be some of our strongest capital efficiencies, whether it's injector conversion optimization, sweep efficiency, just a variety of different flood optimization. So we continue to focus our field and production optimization teams on that in conjunction with supported drilling growth, too, selective areas such as the Bakken, Cardium. I mean those are also waterflood supported areas that we continue to drill and benefit from pressure response there. So it helps to bolster our volumes there compared to primary. So yes, it's something we continue to fund and look at very actively.

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

Thank you, Sylvie, and thanks to each of you on the line 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 1-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.

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.

Good morning, and welcome to Whitecap Resources Annual Meeting of Shareholders being held this morning by audio webcast on the Lumi meeting platform.

I would now like to turn it over to Whitecap's Chairman of the Board, Mr. Ken Stickland.

Thanks very much, Sylvie. Good morning, everyone. What a difference a year makes. We'll have more on that later. I'd like to welcome you to the Annual Meeting of Shareholders of Whitecap Resources Inc. The meeting will now come to order. I'm Ken Stickland, and I'm the Chairman of the Board of Directors of Whitecap, and I'll act as chair of the meeting. Our meeting is being hosted on the Lumi Virtual Shareholder Meeting platform. This allows registered shareholders and duly appointed proxy holders to vote and to submit questions and comments to the moderator to be read and addressed at the meeting. If you have a question or comment, please submit it through the system.

Following the formal portion of our meeting today, Grant Fagerheim, our President and Chief Executive Officer, will make some brief remarks. After his remarks, he'll address any questions.

For the meeting, I'm going to ask [ Jeff Ogle ] to act as Secretary of the meeting; and Jackie Fisher and Paul Bedard, representatives of Odyssey Trust Company, to act as scrutineers. I have received confirmation from Odyssey as to the due mailing of the meeting materials and the financial statements for the year ended December 31, 2025. I direct that this confirmation, together with copies of these documents, be kept by the Secretary with the minutes of this meeting.

We'll now move to a quorum and the scrutineers' report. Business may be transacted at this meeting if 2 or more persons are present, holding or representing by proxy not less than 25% of the shares entitled to vote at the meeting.

Mr. Chairman, the scrutineers' report shows that there is a quorum of shareholders present at the meeting.

I direct that the scrutineers' report be kept by the Secretary and annexed to the minutes of this meeting as a schedule. I now declare that the meeting is regularly called and properly constituted for the transaction of business. We'll conduct each vote today by way of vote cast on the Lumi platform and those submitted by proxy. I understand that the scrutineers have tabulated all the votes received prior to voting cutoff.

If you have previously voted, you do not need to vote again when prompted. By voting again, you will revoke any previous vote made prior to voting cutoff. We will now open voting for all of the resolutions. Particulars of the votes cast on all matters will be made available on SEDAR+ after the meeting.

I would first like to present the financial statements for the year ended December 31, 2025. These are located on the Lumi dashboard page. The next item of business is to fix the number of directors.

My name is Thanh Kang, and I move that the number of directors to be elected at this meeting be fixed at 11.

Thanks, Thanh.

My name is Janice Wood, and I second the motion.

Thanks, Janice. Is there any discussion or questions submitted from any registered shareholder or proxy holder on that motion?

Mr. Chairman, there are no questions on that motion.

Thank you, Tim. The next item of business is the election of directors of Whitecap. The advanced notice date for the nomination of directors having passed under Whitecap's Advance Notice Bylaw, the only individuals entitled to be nominated as directors at this meeting are the persons named as nominees in Whitecap's information circular. Therefore, as directed by the Board and in accordance with the information circular, Scott D. Althen; Grant B. Fagerheim; Jodi J. Jenson Labrie; Vineeta Maguire; Glenn A. McNamara; Barbara E. Munroe; Stephen C. Nikiforuk; Myron M. Stadnyk; myself, Kenneth S. Stickland; Bradley J. Wall; and Grant A. Zawalsky are nominated as directors of Whitecap to hold office until the next annual election of Directors or until their successors are elected or appointed, subject to the provisions of the Business Corporations Act, Alberta and the bylaws of Whitecap.

The next item of business is the appointment of auditors.

I move that PricewaterhouseCoopers LLP be appointed auditors of Whitecap until the next annual meeting or until their successor is appointed and that their remuneration, as such, be fixed by the Board of Directors.

I second the motion.

Thank you, Thanh and Janice. The next item of business is to approve a nonbinding advisory resolution concerning Whitecap's approach to executive compensation.

I move that the nonbinding advisory resolution on Page 26 of the information circular of Whitecap dated March 25, 2026, be approved.

I second the motion.

Janice, thank you. Is there any discussion or questions submitted from any registered shareholder or proxy holder on that motion?

Mr. Chairman, there are no questions on that motion.

Thank you. As voting has been enabled for all previous motions, if a shareholder has not voted yet, please do so now. And we'll just pause to allow final voting.

[Voting]

Voting is now closed. We'll have another pause to receive voting confirmation from Paul that motions have passed.

Mr. Chairman, the scrutineers have advised that all resolutions have been approved by more than the requisite majority and that those nominated have been duly elected as the directors of Whitecap.

Thank you, Tim. I declare the motions carried and the nominees for the Board of Directors elected. We'll now move to other business. Are there any questions submitted to the formal business of the meeting?

Mr. Chairman, we have received a question from Ruth Saldanha of SHARE, who has been appointed as a proxy holder by British Columbia Teachers' Federation holder of [ 22,876 ] shares. Her question is, Whitecap's acquisition of Veren in 2025 made it one of the largest energy companies in Canada. In your financial reports, you highlight physical risks of climate change, including a long-term shift in climate patterns and extreme weather conditions posing the risk of causing operational difficulties. In the latest climate engagement Canada benchmark, Whitecap did not meet the indicator on board oversight of climate governance where years prior, you did, as the CEO is responsible for overseeing climate change.

With global commodity price volatility and general uncertainty, investors would like strong incentivized oversight and competencies connected to transition risks, can you disclose a named position at board level with responsibility over these business strategies and risks? And that's the question.

I'll take that. Thank you for your question, Ruth. The Veren transaction was indeed transformative. Whitecap's governance expressly provides for direct Board oversight of climate-related issues. The best reference for you is the mandate for our Board Sustainability and Advocacy Committee, of which Mr. Fagerheim, as a Director, is a member and Mr. Wall is the Chair. The first item on that Board committee's mandate is oversight of climate-related and other sustainability-based risks and opportunities. The full mandate is available on our website. I hope that addresses your issue. Are there any other further questions on the formal business of the meeting?

Mr. Chairman, we've received no further questions on the formal business of the meeting.

Thank you. There being no further questions, the chair would entertain a motion that the meeting be terminated.

I move that this meeting be terminated.

I second the motion.

The meeting operator is now activating a poll to vote on the termination of the meeting. We'll wait for that result to be tabulated.

Mr. Chairman, the adjournment motion is carried.

Thank you. I declare the meeting terminated, and I'm going to invite Mr. Fagerheim to deliver his remarks on behalf of Whitecap management. Before I do that though, and I turn it over to Grant, I'd like, on behalf of the Board, to personally thank our entire team at Whitecap. 2025 has been a transformative year with the Veren transaction. The dedication and your clear execution have positioned us well going forward. Thank you to everyone. Grant, over to you.

Thanks very much, Ken, and thanks, everyone, for being on the line today. Firstly, I would like to thank our shareholders that have placed the trust in our management team, our staff and our Board of Directors to manage this dynamic and growing organization. The future looks very bright and we are confident that we will continue to deliver strong results as we have over the past year. I would also like to thank our Board of Directors for their guidance over this past year.

In addition to our Chair, Ken Stickland, who was speaking today, we have Glenn McNamara, Steve Nikiforuk, Vineeta Maguire, Brad Wall and Grant Zawalsky. We welcome all of our new Board members. We've been working together for almost a year now, and I would like to thank Barbara Munroe, Jodi Jenson Labrie, and Myron Stadnyk for their contributions over this past year.

Next, I would like to thank and welcome Scott Althen to the Board as of March 1. Scott brings tremendous experience and financial knowledge to our Board, and we're excited to have him join our team. Welcome, Scott. We're looking forward to continuing to build on these working relationships going forward.

Of even greater importance, I would like to thank our entire Whitecap team, both new and long-term Whitecap employees for their efforts over the 2025 year and congratulate each and everyone for the exceptionally strong operational and financial results over this past year. 2025 was truly a transformational year as Kenneth referenced, for Whitecap that included the integration of Veren's assets and personnel beginning 1 year ago today.

Over the course of the year, we made remarkable strides in delivering on our intentions and increasing value from the combined asset base. The Veren transaction closed on May 12, 2025, creating at the time a $15 billion large-cap E&P company, which now is a preeminent $22 billion company, all with keeping leverage under 1x debt to cash flow.

We currently introduce -- we currently produce approximately 380,000 BOE per day and are the largest Alberta Montney landholder, the largest Duvernay operator, the largest light oil producer in Saskatchewan and the fifth largest natural gas producer in Western Canada. We hold 10,500 BOE per day -- 10,500 high-quality locations in inventory, providing decades of growth potential with significant light oil, liquids and natural gas commodity optionality within. For perspective, we're only drilling 265 of those locations in 2026. The office -- and importantly, the field personnel did not miss a beat integrating our teams and assets. We blew through our initial synergy forecast quicker than expected. Included in our 2026 budget was $300 million of synergies. And with continued efficiency gains and operating cost reductions, we're quickly approaching $400 million of annual savings, almost double our original projection of $210 million.

I will now go through specific operational, financial and shareholder achievements made in 2025. From an operational achievements perspective, average production for the full year was 307,245 BOE per day, comprised of 191,155 barrels per day of crude oil, condensate and NGLs, and 697 million cubic feet per day of natural gas. We drilled 113 wells -- 113 unconventional wells in the Montney and Duvernay, and 199 conventional wells across Alberta and Saskatchewan.

We've made significant improvements in all facets of our operations over the past year from well design to development planning to execution and ultimately how we produce our wells have all benefited from substantial technical improvements and collaboration across our teams. Along with stronger-than-expected productivity from our wells, we have improved our capital efficiency by 12% relative to our initial expectations on the combined asset base 1 year ago today.

This has been made possible through improvements in our drilling and completion KPIs, which include a 27% increase in our drilling rates, penetrations and 12% increase in our proppant pump per day. Along with our actively guided completions, we included 24/7 monitoring from our frac room in Calgary. Our frac effectiveness has improved, and we're seeing in our production results. Corporately, our capital efficiency measures have improved by 12% relative to our initial expectations 1 year ago, which is both better and much quicker than we had expected.

Construction has progressed on our 04-13 Lator facility throughout 2025, and we have now accelerated our own production startup timeline to Q4 of 2026. And as of today, we are 70% completed with major equipment such as compression -- compressors now on site, which keeps us on track with our forecast. Our conventional assets are a differentiating factor for Whitecap. The high liquids weighting and cash flow netback, coupled with low decline rate and continuous improvement on well results and inventory provide us stable free cash flow.

Notable achievements in 2025 include the full utilization of monobore drilling in the Glauconite, resulting in a 10% well cost savings on current and future drilling inventory in the area. Next, on the acquired Bakken assets, we are pushing open hole multilateral technology and operations, drilling 2 recent 3-mile open-hole multilateral wells. Pushing the boundaries on this technology will unlock and improve inventory, and we are actively exploring the application of this technology across our conventional -- our entire conventional asset base.

Our year-end 2025 2P reserves now stand at 2.2 billion BOEs, resulting in a long-duration reserve life of over 16 years. That said, we have only booked approximately 30% of our total identified inventory, providing us significant running room and flexibility for decades to come.

Our financial achievements. For 2025, we earned our second highest funds flow per share in Whitecap's history at $2.95 per share, which equates to $2.9 billion, all with WTI averaging less than $65 per barrel and AECO gas at $1.60 per GJ in 2025. Our focus is on generating higher free funds flow for our shareholders. To do this, we are focused on both margin improvements and capital cost decreases. We discussed the strides we made through deal synergies at the outset, which as a reminder, were $210 million upon the close of the deal and now stand at $400 million, made up of capital, operating and corporate costs.

Our free funds flow in 2025 was $900 million, and at current strip prices, this increases to over $2 billion in 2026. We ended 2025 with a strong balance sheet with $3.4 billion of net debt, equating to a net debt to annualized fourth quarter funds flow ratio of 1x.

Our credit rating was also upgraded during 2025 to BBB flat by DBRS, and we issued $300 million of 3-year investment-grade notes at a low coupon of 3.761%. To talk about return to capital -- return of capital to shareholders. Return of capital to our shareholders is a focus of our capital allocation strategy. We currently pay a dividend -- an annual dividend of $0.73 per share, which equates to $735 million for 2025. We also had an active normal course issuer bid where we spent $193 million on share repurchases in 2025. In total, we returned $900 million to shareholders in 2025, another significant achievement.

Our outlook. Our performance is underpinned by a few key attributes that define our strategy and differentiate Whitecap. We went into a bit more detail in each of our first quarter conference call. But in the interest of time, I would just list them off at this time. Operational execution, number one; number two, asset quality, duration and optionality; number three, high netbacks; number four, low decline rate; number five, strong balance sheet; and number six, Whitecap personnel. And to talk a little bit more about that, we believe at Whitecap that our people are our most important asset. And without their intelligence, hard work, dedication and team-first attitude, we wouldn't be where we are today.

And speaking about our Whitecap personnel and our plans to continue to advance and evolve our organization with a practical succession plan, we are pleased to introduce several changes to our executive team from within Whitecap. Firstly, I'm proud to say that Joey Wong will be taking on the role of President of Whitecap, which responsibilities include driving continued technical and operational collaboration along with capital budgeting coordination with the unconventional and conventional divisions.

Joey will continue to report through to myself with my role changing to just Chief Executive Officer, moving to more oversight and strategic direction. Joey has over 20 years of experience -- industry experience and has been with Whitecap for the past 12 years, progressing through various technical and leadership roles and has been responsible for development planning, capital execution and overall performance of our unconventional Montney and Duvernay assets since 2023. Joey is also involved in investor engagement alongside Thanh Kang, our CFO, and myself for the past 1.5 years.

Secondly, Travis Tweit will be promoted to the role of Chief Operating Officer. Travis has over 25 years of industry experience and has been with Whitecap since 2010 under the stewardship of our Senior Vice President, Production and Operations, Joel Armstrong. Travis has been our Vice President of Operations since 2020 and previously was Vice President, Production. Travis has been responsible for directing our operating teams, consisting of our drilling and completion operations where we experienced significant progress and efficiency gains over the past couple of years as a result of his and the team's efforts over the past several years.

Number three, to backfill Travis' role, Jeff Mazurak is being promoted to VP Operations. Jeff has over 20 years of industry experience in various drilling, completion and operating roles and has been with Whitecap since 2021. In Jeff's current role, he has been responsible for our unconventional operations consisting of drilling and completions operations. He and Travis have been working closely together since Jeff joined Whitecap and we're looking forward to bring -- forward to Jeff bringing his experience and expertise to our entire set of assets.

We are very confident that these three individuals, along with various other evolutionary advancement in our organization are able to step into new roles to allow Whitecap to continue on our path of bringing strong operational and financial success to Whitecap.

Lastly, on the personnel side, we advised that one of our key long-term officers of Whitecap is retiring at the end of June after 16 years at Whitecap with a total of 40 years in the energy sector. Joel Armstrong has been a significant and positive impact on our company with his direct oversight of operations, productions and health and safety. A huge thank you to Joel and know that the leaders mentioned above, along with the others, will continue to carry the torch as you have in the past.

In closing, I again want to thank and congratulate our entire team for a remarkable 2025 year, including the very successful integration of bringing 2 sizable asset bases together just 1 year ago today. Operational momentum has continued into 2026, which is outstanding, and we continue to look forward to keeping shareholders in focus as we execute on our business plan this year and well into the future. Thank you for your time today and interest in Whitecap. All the best to you from all of us at Whitecap. Cheers.

That concludes today's webcast. Thank you.

Good morning, ladies and gentlemen. My name is Sylvie, and I will be your conference operator today. At this time, I would like to welcome everyone to Whitecap Resources First Quarter 2026 Results Conference Call.

[Operator Instructions] And I would like to turn the meeting over to Whitecap's President and CEO, Mr. Grant Fagerheim. You may begin your conference.

Thanks, Sylvie, and good morning, everyone, and thank you for joining us here today. There are 5 members of our management team here with me at this time: our Senior Vice President and CFO, Thanh Kang; our Senior Vice President, Production and Operations, Joel Armstrong; our Senior Vice President, Asset Development and Information Technology, Dave Mombourquette; and our Vice President, Unconventional Division, Joey Wong, as well as our Vice President, Conventional Division, 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 first quarter of 2026. We are very proud to report that our technical and operations teams continue to deliver execution through an active first quarter capital program with asset productivity continuing to exceed expectations.

Average crude oil and average production for the first quarter was 391,416 BOE per day, comprised of 242,000 BOE -- 242,107 barrels of liquids per day and 890 million cubic feet a day of natural gas, exceeding our budget expectations by approximately 19,000 BOE per day. Through top-tier execution and strong asset level performance, this production level significantly outperformed our budget expectations for the first quarter. Expecting this performance to continue us to raise our 2026 production guidance by 7,500 BOE per day or 2% to 380,000 BOE per day.

As well, at current elevated light oil and condensate prices, this higher production is generating materially higher cash flow, combined with maintaining our $2 billion to $2.1 billion of capital program. This is driving increased funds flow and profitability relative to our original plan. Our first quarter funds flow of over $1 billion or $0.84 per share, increasing 12% per share compared to the first quarter of 2025.

After capital investments of $626 million, we generated $340 million of free funds flow. This allowed us to reduce net debt to $3.2 billion, while returning $221 million to shareholders through our base dividend. Consistent with our long-term countercyclical capital allocation strategy, we will prioritize debt reduction in excess of -- with excess cash flow at current commodity prices. This strengthens our financial flexibility to redeploy capital towards share repurchases accelerate growth or tuck-in consolidation opportunities in the future.

The progress we have made since closing the Veren acquisition 1 year ago has been remarkable. Improvements within our control, including execution, well design, development planning and production practices supported by rigorous technical analysis and cost discipline have delivered the results we are experiencing today.

Whitecap is positioned to capitalize on commodity price cycles inherent to our industry, and the current environment is no exception. Our operational execution allowed us to capture additional benefit of higher prices in March and April to date as we have completed the first quarter capital program with all the planned light oil and condensate wells brought on production on or ahead of schedule prior to spring breakup.

We were running 18 drilling rigs during much of the first quarter, and now we'll continue to run 6 rigs through breakup on our unconventional and glauconite assets, and we'll be ready to hit the ground running on our light oil conventional assets in Alberta and Saskatchewan once breakup subsides later in the second quarter.

We are maintaining our 2026 capital budget. Any potential future adjustments will support increased production growth in 2027 within our 3% to 5% target should higher crude oil and condensate prices persist at this time. I will now pass it on to Thanh to further discuss our financial results. Thanh?

Thanks, Grant. Our first quarter funds flow of $1 billion was driven by strong operations, continued cost discipline and our ability to capture elevated light oil and condensate prices during March. For the quarter, our fund flow netback increased to $29.12 per BOE, up 5% year-over-year despite Canadian dollar WTI crude oil prices down approximately $4 per barrel and AECO natural gas prices down approximately 7% as compared to the first quarter of 2025.

This improvement was driven by stronger price realizations across crude oil, condensate and natural gas, along with a meaningful reduction in our operating costs. Realized pricing for crude oil and condensate benefited from a higher proportion of condensate in our production stream, which typically trades at a premium in Western Canada due to strong oil sands demand for diluent.

Our core growth areas are focused on light oil and condensate-rich assets, which we expect will continue to support strong price realizations. Our natural gas production benefited from price diversification with realized pricing of $3.18 per Mcf, approximately 60% higher than the average AECO price. While diversification carries higher transportation costs, the incremental revenue more than offset these costs during the quarter.

Our long-term target remains to diversify 50% of our natural gas volumes away from AECO. We have made significant progress reducing operating costs, and we continued this trend in the first quarter. Our $12.02 per BOE operating expense was down 11% year-over-year, reflecting ongoing efficiency gains across our operations. As a result, we are improving our full year 2026 operating cost guidance to $12 to $12.50 per BOE.

The sharp increase in strip crude oil prices through to the end of 2027 had a timing impact on our net income for the first quarter. We recognized an unrealized loss on commodity contracts of approximately $500 million or $0.40 per share against our net income. The benefit of higher commodity prices will be realized over the coming months and years.

During March, we also prudently added to our crude oil hedge positions, locking in attractive prices for 2026 and 2027. For the remainder of 2026, we have approximately 35% of our net crude oil production hedged at an average swap price of approximately CAD 95 per barrel. And for 2027, we have 23% of our net crude oil production hedged at an average swap price of over CAD 91 per barrel.

Our natural gas hedge positions are largely unchanged with strong prices locked in for the remainder of 2026, with 28% of production hedged at an average swap price of over $4 per GJ and in 2027, 13% of production hedged at an average price of approximately $3 per GJ. Bringing this together and incorporating our increased production and strong crude oil and condensate pricing, we forecast $4.3 billion of funds flow for 2026 at current strip prices. This translates to $2.2 billion of free funds flow.

Our balance sheet is very strong. And as Grant noted, we will prioritize debt reduction with excess funds flow at current commodity prices. Our current net debt of $3.2 billion represents a net debt to annualized first quarter funds flow of only 0.8x. At current strip prices, our year-end net debt would be reduced to $2.2 billion, which equates to a net debt to funds flow ratio of only 0.5x.

Finally, during the first quarter, we proactively reduced our credit facility by $500 million, lowering standby fees and extending the maturity to September 2030. I will now pass it off to Joey for more remarks on our unconventional results.

Thanks, Tom. Our unconventional division delivered another strong quarter with production averaging just under 240,000 BOEs per day, approximately 4% above our budgeted expectations. Consistent with prior quarters, this outperformance comes largely as a result of strong new well results and continued improvements in execution.

Aggregate well performance exceeded expectations by 10%, while drilling and completion activity came in approximately 2 days per well faster than planned. This cycle time compression has been a consistent trend for the division over the past several quarters, stemming from improvements to our drilling and completions key performance indicators. Those indicators, as measured in meters per day of drilling or tonnes per day of completions operations have seen improvements of 27% and 12%, respectively, as compared to historical levels.

Importantly, these aren't just pacesetters, but they are average gains and are being realized across multiple assets and programs. This speaks to the consistency of execution improvements being realized across the portfolio. These improvements are being driven by a combination of well design optimization, continued advancements in completions execution, including the application of actively guided frac operations and the use of data-driven execution workflows across our asset base.

We are leveraging a deep proprietary internal data set of over 1,100 Montney and Duvernay wells rich with producing and execution data. What we're now seeing is the benefit of scaling learnings and applying them consistently across our expansive portfolio of Montney and Duvernay development opportunities.

These efficiency gains are now incorporated into our updated guidance. We have adjusted our activity levels to reflect these improved cycle times, reducing our unconventional rig count to 6 from 7, while maintaining our capital program. This effectively smooths capital through the balance of the year, improves rig utilization and enhances overall capital efficiency without increasing spend.

Turning to Karr. We are pleased to report that our 2 planned plug-and-perf pilots in the first half of the year have been executed successfully. From an execution standpoint, results have been very encouraging. Effectively stimulated stages, which is one of our key measures on execution, exceeded 95% across all 7 wells and overall costs came modestly below budgeted expectations.

This translated into an approximate $2 million per well cost advantage relative to single point entry completions in the area. The 2 pads are now in their early time cleanup production phase, and our technical teams are gathering important flowing and diagnostic data. Further success on these subsequent levels of evaluation will define the overall success of the pilots.

The level of cost improvements has the potential to drive approximately 20% uplift in well level economics, which represents a meaningful opportunity to add incremental value to this land base. We have a third pilot pad planned for the second half of 2026 for the Gold Creek area, which is to the north of these 2 initial pads.

We will incorporate learnings from this pilot program to inform future development decisions as we continue to pursue meaningful value-adding optimization initiatives on these lands, while controlling the pace to ensure we are not exposed to material corporate level risk.

It is important to note that with improvements in our overall completion execution and reduction in cycle times, the cost difference between single point entry and plug-and-perf has narrowed significantly in some areas of our land base. The important part is, ultimately, we feel comfortable deploying either completion technique and we will let our technical and economic analysis determine the optimal technique on a pad-by-pad basis.

At Lator, our facility build continues to progress very well and now stands at approximately 70% complete with both cost and schedule remaining aligned with our accelerated on production timing for the fourth quarter of this year. Overall field construction is well advanced with the majority of major equipment now delivered to site, which materially derisks the remaining construction time line and subsequent ramp-up.

That ramp to nameplate capacity of 35,000 to 40,000 BOEs per day of throughput is expected over a period of 12 to 18 months from the in-service date of the facility. In parallel, we continue to gather subsurface and production data from both legacy and new wells in the area. As we continue to refine our understanding of the asset through execution, we will further assess and incorporate available upside and we'll adjust our expectations and development plans accordingly.

In Kaybob, wine rack development is now fully underway across our high confidence lands, which represent approximately half of our undeveloped acreage in the area. Based on results from this configuration, which was first piloted with well spud 2 years ago, we are seeing consistent improvements of 10% to 20% in both initial production rates and expected ultimate recovery. We are very pleased with the incremental value that has been added to these lands through the application of rigorous, measured and thoughtful optimization.

Building on that foundation and leveraging a wealth of information from the nearly 50 wells drilled in this configuration, we are now progressing to the next stage of optimization within a subset of these lands. This involves targeted downspacing pilots on 2 pads in the southern portion of the Kaybob asset base.

This area has demonstrated low inter-well communication when developed with this wine-rack configuration and as a result, has provided the opportunity to improve the area-based recovery of these lands through this downspacing from an average of 5 wells per section or 330 meters inter-well down to 6 wells per section or 275 meters interwell. When combined with the gains realized from wine racking, we estimate a benefit of 20% to 25% to asset values of affected lands through the addition of an additional 20 to 25 incremental inventory locations.

Lastly, at Resthaven, we will be commencing our first delineation campaign of these prolific lands with a 2-well pad to be spud in the coming months and brought on production near year-end. While the asset is more gas weighted than the balance of our current development focus, wells in this area can still be expected to produce an impressive amount of liquids, and this 2-well pad will begin to assess that along with validation of our models for the estimates of modern day optimized development on these lands.

This work is an important component of our broader technical readiness strategy, ensuring that we continue to advance our understanding of key assets and position them for development at the appropriate time. With that, I will now turn it over to Chris to discuss our conventional assets.

Thanks, Joey. Our conventional division hit the ground running in the first quarter of 2026, with momentum carrying forward from 2025 as we delivered strong production performance of over 150,000 BOE per day of light oil-focused volumes. Outperformance of 6% relative to budget expectations was achieved by stronger-than-expected growth volumes and timing improvements, supported by a very active 9-rig Q1 program, along with solid baseline performance as our teams continued to enhance efficiencies through optimization initiatives and improved operating conditions.

Our high confidence and high-margin conventional assets continue to underpin Whitecap's sustainability. With an 80% liquids weighting, the majority of it being light oil, a sub-20% decline, 52,000 barrels per day of dedicated EOR production and extensive infrastructure already in place, we were well positioned to capture meaningful upside as oil prices strengthened materially late in the first quarter.

This diversified portfolio continues to provide Whitecap with a significant competitive advantage, allowing us to maintain budget flexibility to allocate capital across multiple high-quality quick cycle opportunities that could rapidly add light oil production. Saskatchewan was our most active conventional area in the first quarter with 45 wells drilled utilizing up to 6 rigs, primarily targeting the Frobisher, Bakken and Viking.

Q1 outperformance was driven by continued enhancements to our growth programs with improved cycle times, more focused development sequencing alongside strong base production supported by lower-than-anticipated downtime, optimized waterflood performance and increased service rig utilization, an exceptional start to the year.

Our Frobisher program saw 19 wells drilled with 3 rigs, which represented the most active Q1 on these assets to date. Our teams saw operational improvements on drilling costs with a 7% reduction in a dollar per meter metric and a 15% reduction in equipping costs relative to historical performance.

In the Bakken, our open hole multilateral development continues to push technical and operational boundaries, highlighted by the recent drilling of a 10-leg open hole multilateral well with lateral lengths up to 3 miles. With over 43,000 total meters drilled, this represents the longest well drilled in Canada and underscores the strength of our technical and operational capabilities.

The well was recently brought on production in April and positive results are expected to enhance our inventory depth, improve long-term capital efficiency and further validate the applicability of open hole multilateral technology across our conventional asset base. These inventory enhancement initiatives are characterized as optimizing lateral lengths and reservoir contact to maximize per well economic metrics, our primary objective.

Shifting to Alberta conventional assets, which delivered the majority of our outperformance of approximately 5,500 BOE per day. Base optimization initiatives, combined with access to previously unavailable third-party infrastructure capacity in the Glauconite contributed to approximately 3,000 BOE per day of upside in the Glauconite volumes during the quarter.

The balance of outperformance comes from new well growth and volumes from our Glauconite, Cardium and Charlie Lake assets, all areas that have shown year-over-year enhancements such as an increased lateral length and optimized completion designs. With that, I'll turn it back over to Grant for his closing remarks.

Okay. Thanks very much, Thanh, Joey, Chris, for your comments. I want to reiterate how remarkable these results are, especially when coming less than 1 year after combining the 2 sizable companies and asset bases. The integration has been both rapid and successful, and our team is already delivering meaningful gains in productivity and free funds flow as we've discussed.

Our performance is underpinned by a few key attributes that define our strategy and differentiate Whitecap. #1, operational execution. Our operating capabilities continue to improve, driving shorter cycle times, greater efficiencies, lower cost and strong production results. #2, asset quality, duration and optionality. We have approximately 10,500 drilling locations across light oil, condensate-rich, liquids-rich and natural gas assets, providing decades of inventory. The quality of the inventory, combined with our track record of execution continues to drive consistent outperformance.

#3, high netback. Our predominantly light oil and condensate production generates strong funds flow netbacks, further supported by cost discipline. Our focus on controllable costs continues to drive margin expansion. #4, decline rate. Our current decline rate of 29% lowers the capital required to sustain production and supports higher free funds flow.

#5, balance sheet strength. Maintaining a strong balance sheet provides the flexibility to execute our capital allocation strategy, including returning capital through our base dividend, pursuing share repurchases, accelerating growth when returns are strong and evaluating accretive acquisition opportunities.

And #6, probably most important, Whitecap personnel. Across our office and field personnel, we enjoy the exceptional results because of the commitment and dedication of our talented team. Together with these attributes differentiate Whitecap and enable our results, we delivered in the first quarter. We remain focused on driving further profitability and delivering superior long-term shareholder returns.

With that, I'll now turn the call over to the operator, Sylvie, for any questions.

[Operator Instructions] And your first question will be from Dennis Fong at CIBC World Markets.

Congrats on an incredibly strong quarter. My first question is probably directed a little bit to Joey. You've commented in the past as well as in your prepared remarks today around kind of your view that effective stimulation along the length of the wellbore is a really strong indicator for, a, a successful completion, but b, also the possibility of kind of improved productivity.

As you evaluate the plug-and-perf wells at Karr, can you talk to us about a little bit of the, we'll call it, the metrics of the information that you're trying to gather that kind of prove out the success in terms of what you're trying to achieve here with plug-and-perf?

And then secondarily, can you highlight maybe what kind of rock characteristics or targets create kind of a viable opportunity to deploy plug-and-perf versus single-point entry as you kind of take this pilot project and roll in and potentially experiment around other areas of the field.

Dennis, thanks for that. So yes, I appreciate you highlighting there. That's exactly how we view the evaluation process there is like you said there, we noted that the execution went well. Very pleased, of course, and reiterating there able to even optimize along the way with that the actively guided frac operations that we do have.

And as we noted there, yes, that's good, and we're happy with it and the greater than 95% completion effectiveness is now -- is logged for these wells, and we're there. The second phase, as you're asking about here, is the information gathering phase on the early production. And what we're looking at is -- it's a wide suite of diagnostics that we look at.

And important to note actually as well, Dennis, that the diagnostics that we do is not unique to this pilot, but part of our normal course of operations when we're looking at assessing the effectiveness of the development of these lands. So to give kind of a view into what we're looking for, and again, it's done through a wide variety of diagnostics. But ultimately, what we're looking for is the geometry of the fracs and if it conform to our expectations to see how -- so that would be the first one.

The second one would be to see how the rock has responded to that treatment, how much rock we've contacted. We're also looking to see where the contribution for production is coming from along the lateral to make sure that it's uniform there. And then also importantly as well, we're looking at how the wells are interacting with each other on the pad and with respect to wells that exist in the area.

So we're taking a look at all of the producing and interpreted information that comes from all of those to come up with a full picture to understand, okay, yes, the execution went well, but is the development actually getting to the ultimate end that we're looking for, which is an optimized result on an economic basis.

And it brings me to actually get to your second question there, what rock characteristics are good for plug-and-perf. I mean, at a high level, you're going to be looking for rock that's relatively homogeneous, that you have a history of a design and associated execution on that you can build again that confidence around the interpretation on the 2 phases that I talked about there, both execution and the subsequent on production.

Generally speaking, the Montney and Duvernay have those characteristics. And that's why 90% to 95% of the asset bases that you see in the Montney and Duvernay and similar ones in the Lower 48, for example, are done with the plug-and-perf technology. But there will be pockets within there that you see slight differences in the rock or different hazards or risks that you want to control around that you might then revert to a different technology or a different development design.

And again, I know we've talked about this before, but it's worth reiterating right now that the completions technology is one of many design inputs that we have. We adjust things like our tonnage intensity, the nature of our proppant into the slurry, where we land the wells, all of those things go into that in order to, again, drive the most effective development that we can on the asset base.

So I kind of went around on a bunch of different topics there, Dennis, on your question there, but did that cover it mostly?

No. Yes, I really appreciate that context there. You definitely answered the question. My second question here is kind of shifting towards the conventional side. So you obviously showcased really a lot of kind of innovation, especially with a 10-leg multi-later at a 3-mile length. And this really kind of builds off of what you highlighted at the Investor Day.

I was actually hoping to find out, a, how do you think about frankly inventory replacement within the conventional side just as you're able to convert, we'll call it, additional premium as you highlighted -- or sorry, additional inventory into premium inventory? And then how do you also balance targeting kind of, we'll call it, higher quality reservoir in terms of these opportunities versus ones and testing opportunities that may be deem kind of lower quality reservoir and then seeing kind of what the delta is in terms of well performance?

Dennis, thanks for the question there. As far as inventory goes, we're always trying to maximize, I'd say, the capital that we're trying to deploy here and enhance our learnings. I mean I think our teams have done a really good job of that time and time again, being very focused on how do we reduce our overall capital perspective or capital deployment, I should say.

Examples of that would be as assets transition from 1 mile to 2 miles to 3-mile development, you really start to see those capital efficiencies continue to improve. And I think our teams have done a great job showcasing that. With respect to how we're upgrading that inventory, our teams are always very pragmatic in understanding how we continue to push forward and allocate, I'll call, dollars to more strategic initiatives or initiatives that would be not our premium style inventory.

So we continue to enhance that inventory from a Tier 1 perspective. So I guess where I'm going with that is we always think about derisking our lands in a very pragmatic fashion way. And we do allocate a small percentage of dollars to that every year.

Again, one of the benefits of our portfolio having such a strong Tier 1 inventory position is we don't really need to take those unnecessary risks. So we will allocate small percentages of strategic dollars to helping to validate and enhance that. From a targeting quality perspective, I think the Bakken open hole multilateral will be a really good example of that. Where we can take open-hole multilateral technology and help us to upgrade potentially lower reservoir that we wouldn't be targeting with stand-alone drills, I think lengthening and enhancing lateral lengths towards capturing more reservoir in the most efficient way possible is really the key focus and target for our teams.

And I think, again, the Bakken is a really good example of that. So we're always cognizant of that inventory that's somewhat -- requires some more delineation and some more risk. And I think that continuing to enhance lateral length is probably a key for that -- for us. And again, I'll just reiterate that we don't need to take any unnecessary risk because we benefit from having such a strong inventory portfolio on the conventional side that we really are in an enviable position to be very tactical in how we deploy those opportunities.

Next question will be from Michael Harvey at RBC Capital Markets.

So a couple of quick ones. I guess, first on the capital costs, are you seeing any signs of higher capital costs in your business? And if so, kind of what service lines would those apply to? Or if not, kind of what do you expect to see over the next year or so? Just to help folks frame that out?

And then second, I know I saw the comments in the release, but is there a commodity price environment that would cause you to increase your capital program this year and next? My sense is probably not for now, but any color on what could change and kind of what might drive that would be appreciated.

Michael, Joey here. So on the service cost side, the short answer is nothing material as of yet. We'll probably expect to see some pressure on things that are more fuel intensive. Of course, diesel is a pretty acute thing that everyone is going to be feeling. But to the extent that we've been able to -- we've locked down a number of our services with contracts that largely shelter us from that.

And on the diesel side, probably worth noting as well, when you look at the amount of fuel that we use in our drilling and completion operations, like the direct diesel that we'd be using on both drilling rigs and the frac spreads. Prior to this, we had already displaced somewhere between 2/3 and 3/4 of that use on the unconventional side, at least from diesel and towards our own sourced natural gas that's sourced from our own operations. So we're naturally already protected against that as well.

So where we expect to see it, like I said, there should be marginal and the setup for us at least is good so far to be able to navigate through this. On the capital side, there maybe look to Grant to answer that one.

Just on the -- you asked about increasing capital program. And our objective here, as we talked through the presentation is we do think countercyclical in the higher pricing environment. It's not as to increase our capital program, especially with the type of results that Joey, Chris and the operating team are bringing forward, use that as a time to strengthen your balance sheet for future opportunities.

So if there was any increase that we'd be considering, it'd be in the fourth quarter that would have an impact on 2027. So in the meantime, we'll enjoy the benefits of the higher prices, specifically on crude and condensate prices at this particular time and use that to drive a very strong -- much stronger balance sheet as we advance forward. We've not have problems with the balance sheet, but our long-term strategy has been in a higher pricing environment, delever as quickly as you possibly can and prepare yourself for future opportunities in how you want to deploy that capital.

So I don't -- you wouldn't expect to see us increasing capital. We'll review our fourth quarter as we go in -- as we go through the balance of the year. But at this particular time, there will be no increase from the $2 billion to $2.1 billion.

Next question will be from Sam Burwell at Jefferies.

Just curious like the updated raised guidance, does that contemplate any steeper than usual dip in production in 2Q on breakup? Just wondering like I would assume that we should assume that 4Q production should be at least as high as 1Q. But just any color you can give on the cadence of production over the next 3 quarters would be helpful.

Yes. Thanks for that question here. It's Thanh here. As we would have talked about before, actually in the third quarter, we've accounted for some turnaround activity at PGI, Patterson as well as in our Glock in Central Alberta there.

And so that will impact our production somewhere in that 12,000 to 15,000 BOEs per day in the third quarter. What you'll see is the outperformance, that 19,000 BOEs per day that we saw in the first quarter. A component of that is going to be performance related and a component of that is going to be timing, right?

So what Joey talked about in terms of the compressed cycle times. So as you can appreciate, some of that production is being moved forward and actually makes it harder for us to achieve our fourth quarter numbers. So I think we're still very comfortable uplifting full year in that range of 7,500 BOEs per day. But more importantly, as you think about Q4, it's still going to be in excess of that 380,000 BOEs per day is what our expectations are.

Okay. Got it. And something that I think we're noticing is the premiums that light oil and condensate are getting to WTI, you guys called out explicitly in your release. So curious what you attribute that to? I'd imagine it's probably some dynamics that are further downstream in the U.S. But I guess more importantly, like how long do you guys expect that to sustain?

Yes, it's Thanh here again. I'd say that, obviously, with the current Middle East conflict, there's lots of dislocations that are currently happening. I mean the -- I think the primary contributors would be certainly on the light side there, inventories are still relatively low, and there's strong export demand for light oil.

On the diluent side there, the domestic demand with growth in the oil sands, I think that remains strong. If you look at pricing for the month of May, I mean, it was positive $9 and positive $8 for lights oil and condensates, respectively, there.

As we think about the second quarter, we're still seeing pretty strong if you look at the strip pricing there, it's trading somewhere in that $3.76, that's a premium for the second quarter on MSW. And on condensate, it's about $2.60. Our forecast is a little bit more conservative. I'd say that we're running still at a discount of $2.50 on the lights and minus $1.50 on the condensate there.

So I think Q2 is still going to be a very, very strong quarter for Whitecap here, considering we're producing 138,000 barrels a day of light oil and 55,000 barrels a day of condensate. So I think if the conflict continues to persist here, I think you could see this dislocation continuing, but we're certainly not embedding that in our guidance at this time.

Next question will be from Jeremy McCrea at BMO.

Maybe, Thanh, just going back to your guidance question there. I'm just thinking about these plug-and-perf designs and just the improvement that you're seeing, how much have you embedded these success with the results into your guidance?

And is there more to come here as you basically replicate this plug-and-perf throughout other areas here going forward? And maybe if there's any additional details in terms of how rapidly you want to deploy this new design here throughout the field.

Jeremy, I'll take this one, Joey. So your question of what's been incorporated in the rest of the year, as it stands right now, the early time flowback is within our expectations. So there really isn't a change to what we think what these pads are going to do. But we have recognized the cost advantage there, the $2 million per well that we spoke to, which, again, we're quite pleased about. So as it stands right now, it's -- everything is on track with that.

Now with respect to your other question there, how quickly we'd look to roll that out and how applicable this is to all the other land, of course, and trying to get read through to further capital efficiency gains is, of course, what we're -- I'm sure everyone is thinking about, including us. And it's probably worth taking a step back and looking at this. We observed that there was an ability to improve both design and execution on the plug-and-perf deployment, particularly on these lands throughout the asset base, but again, particularly more acute on these lands.

And the goal has been all along repeatable and optimized frac geometry and doing that at the lowest risk-adjusted cost that we can at its most fundamental. And of course, if done correctly, if done appropriately with the right design and the right execution, the 2 results should be effectively the same. It's not like plug-and-perf is getting us a better well. We're just getting the same, again, optimized frac geometry that we've designed around throughout the other dozens of inputs that I spoke to in the response to Dennis' questions there.

So in terms of then assessing how quickly we want to roll this out, we'll be looking back at these pilots and looking to those diagnostics that we've outlined there to say, okay, based on what we're seeing here, do we see a reduction of risk on associated lands that we want to try this on. Can we advance the next page of pilots with a certain level of confidence? Do we need to go to another area in order to validate something that's a little bit gray on some of those dozens of technical indicators we're looking at.

It's going to be multifaceted as we look at it. But again, when we're -- just to reiterate, and again, I mentioned this to Dennis as well, this is a risk-adjusted economic decision that we're trying to put into place to improve the capital efficiencies of these lands. And it's no different than some of the other things that we've looked at that have moved the needle already to date. We talked a lot about, again, where we're landing wells in the Duvernay well design changes, whether that's larger casing size or how we're actually landing the wells, all of those different things leading to ultimately what those improved KPIs that I spoke to there on the actual execution there, which has driven the improvement to capital efficiency, which we have highlighted in our corporate deck now, which have improved by 12% as compared to historical levels there.

So again, what we're going to do, and it's worth reiterating one more time, we're going to look at the data and then understand what the best way is to go from there. And in portions of the land base there, and as mentioned in the prepared remarks there, if in portions of the land base, we see improvement to single point entry and that cost advantage isn't quite as wide, we're more than happy to stick with that technology in portions there as well.

So yes, to be determined there, Jeremy.

Okay. And maybe just an unrelated question here. I keep looking at your 40-plus years' worth of inventory. You talk about your premium inventory versus just regular inventory, I guess, is maybe the way to say it. Is there plans to potentially dispose of some of the nonpremium inventory here, just given where valuations have moved for a lot of the logical buyers that can buy this?

No. At this particular time, Jeremy, I mean, what we're wanting to do, the way we think about it is we've got premium inventory and then it's not as though the non-premium inventory, if you want to use that terminology, isn't economic. What we want to do is continue to mature what I'll call our lower-tier inventory into something we may spend capital on.

And we're not looking for third-party capital at this particular time. There will be no particular reason for us with advancing technologies at the pace this has taken -- is being undertaken. We don't feel there's any need to dispose of or utilize up the inventory set that we do have, both in the conventional and the unconventional portion of our business.

So if it gets to be that we're not deploying capital over a 5-year period of time on these assets and we're definitive about that, sure, we'll look to maybe bring in third-party capital or disposal of those assets. But certainly not in a hurry at this particular time when Canadian oil is trading at $142 a barrel, I can tell you we're hanging on.

Next question will be from Travis Wood at NBC Capital Markets.

I guess my question is in the line of what Jeremy was getting at and maybe a bit more broader. But with the big Q1 beat, you've kind of flagged pretty impressive productivity changes, faster cycle times. But as you look across that performance through Q1 and think about the rest of the year, how much of that outperformance would be related to more structural changes that you guys have implemented versus maybe some timing nuances from onstream a little earlier than expected?

And then how do we think about that through the rest of the year as you capture structural changes, but then also the nuances of timing?

Yes. Perfect, Travis. I'll start this one and maybe Chris can hop in on the conventional side there. And actually, where I'll start is actually the last point you made there in terms of timing and leaning back to what Thanh said there. Timing is a big component of what we're seeing in Q1.

So when you look at the -- on the unconventional side, the beat that we had there as compared to our internal expectations, about 2/3 of the beat was on performance. So that was exceeding our expected productivity on the wells by an aggregate 10% like we had highlighted. The other 1/3 is those cycle times. So it gives you a sense of where we notionally see things.

Now what's built in for remaining outperformance on these wells, where we've seen direct relationship between cause and effects, how we're landing wells, how we're fracking them, we do build those in live into our expectations and that would be incorporated into not just 2026, but as we build out our inventory and evaluate the whole asset base that we look at.

But where we're not seeing something that we can draw a clear causal relationship, we'll stick to the way that we generate the type curve in the first place, which is to look at area averages and lean towards that and continue to stay with that. So it's a mix of both that we're seeing there, Travis, but again, partially recognized maybe Chris, on the conventional side.

Yes. Thanks, Travis. And on the conventional side, I mean, a very similar theme. Everything we build is around risk forecast and normalized operating parameters. And we think about the conventional side, about 50% is growth and 50% is base from an outperformance perspective. And a large chunk of that really was the block optionality from an egress perspective. That really is one of the benefits of having such an expansive interconnected systems that we can optimize very quickly.

So when that capacity did become available for us, I mean, we very quickly acted to take advantage of that. And that helps us not only on the base from a 3,000 BOE perspective, but also on our growth volumes, too. It does give us that ability to take advantage of additional growth volumes, too. But to my point, we would view that as kind of a short term. It's not something we can really roll into go-forward plan per se.

So again, very, very beneficial from that perspective, but we're not going to be rolling in those kind of egress optionalities going forward, but we will continue to take advantage of it where we can.

Okay. Perfect. And then I guess, related to hedging, and Thanh, this will be for you. Following the Veren deal, you talked about goals around and a target rather about diversification for gas.

How can we bridge -- like just from a timing perspective, how do we bridge kind of this 2026 diversification, where you're 50% exposed to AECO, compressing that down to 1/4 on the target date. How do we bridge that as over time? Is there kind of interim targets on that target date, if that makes sense?

Yes. Thanks for that, Travis. I think the way that we think about diversification is very similar to the way our strategy is from a hedging perspective, right? So I mean, we'll continue to layer on incremental positions to be able to get that targeted 50% exposed outside of AECO. So what you won't see us do is take these big positions one way or the other. And what we're trying to do is mitigate risk versus increase that.

So the one that we did with Centrica is a good example, where it was 50 million a day, it's roughly 5% of our total gas volumes there. And so as we think about moving into 2028 here, '29, I think over the next 2 to 3 years here, we'll have lots of opportunities, whether it's on the financial or the physical side to be able to price diversify that.

And obviously, we've been able to see the benefits of that, both in the fourth quarter of last year as well as the first quarter of this year here, where we realized a significantly higher price than AECO. But it's absolutely at the forefront here, Travis, and our marketing team is well underway in terms of being able to move us towards that 50% sometime in '28, '29.

Next question will be from Phillips Johnston at Capital One.

It's pretty obvious we've seen an increase in large-scale M&A in Canada over the past several quarters, including Monday's announcement. Grant, I just wanted to get your high-level thoughts on just the overall M&A landscape for the industry and also where you think Whitecap fits into the equation. Obviously, the company participated in that consolidation. So I just wanted to gauge your appetite for both larger scale or smaller scale acquisitions looking out over the next few years.

Yes, Phillips, thank you. I mean, yes, the recent -- the announcement, the Shell/ARC announcement, I think has put very much a limelight on what is taking place in the Canadian sector because of it -- and there's a good reason for that. I mean we -- on a relative basis, if we can get this right with the policies and regulatory environment in Canada, where we can deliver our products to international markets and further into the United States of America.

I think the consolidation will continue, both small scale and large scale. Large-scale M&A activity, there's fewer and fewer candidates out there for that for large-scale M&A activity. With respect to where we fit on large-scale M&A activity, we talked about, as I referenced earlier, about being countercyclical and making sure that we have a strong balance sheet we're setting ourselves up for opportunities in the future, whether it's large scale or small scale.

So participating in that, I think that we're going to see and continue going to see because of the inventory set and the quality of inventory in Canada, specifically people are hyper focused on the Montney and Duvernay at this particular time, but there's other assets in Canada that are very strong as well.

Small-scale acquisitions is -- will always be on our radar for consolidating in and around our existing assets. That will always be as part of our DNA that we do look at where we can own our assets 100% in each one of the areas, the high netback areas and uncomplicate our business into the different facilities and infrastructure we have, we'll continue to look at that.

So I think Canada is unbelievably well set up with the asset duration and quality we have. And if the investing environment continues to improve through regulatory reform, I think Canada can be very well served from an oil and gas perspective.

That is really good color. And then just to clarify the comments on the 3,000 a day of volume boost at Glauconite. It sounded like your comments imply that that's not necessarily repeatable. Did you mean that, that was temporary capacity that opened up? Or is that sort of permanent capacity that's opened up, but it's not, I guess, further gains like that aren't really repeatable?

Phillips, it's Chris here. Yes, that's right. From a Glauconite perspective, again, I mean, just to reiterate my comments, and we'll continue to use optionality in egress when it does present itself.

In the case of the Glauconite here, I mean, we were expecting that service to be filled by some other producers. The case turns out that it was not filled by a third-party producer, so we took advantage of that. And going forward, we have not baked in additional upside from a Glauconite egress perspective. However, we have put forward additional base and growth volume outperformance to the rest of our conventional plays.

Next is Patrick O'Rourke at ATB Cormark Capital Markets.

Congratulations on the performance this quarter. Just thinking about Lator and sort of the rollouts here, what are the key items remaining to gating of this asset? And what does sort of the evolution of the production look like here going forward from a timing perspective?

Patrick, so with respect to remaining work, it's just to finish the completion or finish construction of the facility there, like we said, 70% complete is definitely a nice place to be when you were looking at, again, that Q1 start-up. So really, it's just following through.

And the reason we did highlight in the prepared remarks there, the major equipment being delivered is just to give a nod to the fact that -- there are some longer lead items out there in the world these days, particularly drivers on compression that are challenging some time lines in some facility build-out, and that's a global thing. That's just draw on rotating equipment with demand coming for power generation associated with all the build-out on AI and whatnot.

And so like I say, we put that in the remarks there to note that we're through that. Compressors are there on lease, they're spotted on piles and they're ready to go. So ultimately, like we said, they're materially derisked for our Q4 on prod. And then with respect to the production profile there, anywhere from a 12- to 18-month ramp to production.

And again, that's intentional. And probably worth noting there, too, that while we have the ability to ramp faster if we wanted to, we enjoy the optionality to be able to deploy our capital throughout our asset base, which we're doing right now so that we don't have to ramp that facility right up to the 35,000 to 40,000 BOEs a day on day 1.

We dispersed the capital throughout the land base level load, not just the operations themselves, but then, of course, the associated gathering and processing facilities and allow for optimization that way in that 12- to 18-month period.

Okay. Great. And then maybe with respect to the hedge book here and think about the backwardation and the time spreads out there, you guys have been fairly disciplined and regimented about hedging out into the future. But how does the current environment sort of shift your strategy so you can preserve some of that upside?

Yes, Patrick, thanks for that question there. Our strategy for hedging really doesn't change, right? So what it's meant to do is stabilize our cash flows in a low pricing environment there, and it's not meant to be speculative. We certainly have a view on where commodity prices are. But what we're trying to do is lock in the ability to pay for our dividend and as well as maintain our production.

So 25% to 35% is what we're targeting over a 2-year period of time here. And so as we think about even getting up to that 35% there, the ability to stabilize our cash flows, but also allows our investors to participate up to 65% on the upside there. So we feel very comfortable about the strategy on a long-term basis and certain dynamics haven't changed that strategy.

And at this time, gentlemen, we have no other questions registered. Please proceed.

Okay. Thank you, Sylvie, and thanks to each of you on the line today who continue to support us. 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 first quarter.

To our shareholders, we look forward to updating you on the progress through the remainder of the year and into the future. All the best to each of you 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. And at this time, we ask that you please disconnect your lines. Enjoy the rest of your day.

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 Q4 and 2025 Results and Reserves Conference Call. [Operator Instructions].

And I would like to turn it over to Whitecap's President and CEO, Mr. Grant Fagerheim. Please go ahead.

Thanks, Sylvie, and good morning, everyone, and thank you for joining us here today. There are 5 members of our management team here with me today, our Senior Vice President and CFO, Thanh Kang; our Senior Vice President, Production and Operations, Joel Armstrong; our Senior Vice President, Business Development and Information Technology, Dave Mombourquette; our Vice President of Unconventional Division, Joey Wong; and our Vice President of the Conventional Division, 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. 2025 was another transformational year for Whitecap as we follow up to our 2022 transaction with XTO Canada. The combination with Veren was deliberate. We pursued it to increase scale, strengthen our asset base, add to our enviable inventory position and to structurally improve profitability.

The strategy is already delivering measurable results. We exited the year with strong operational momentum. Fourth quarter production averaged over 379,000 BOE per day, exceeding expectations as a result of accelerated timing and asset level outperformance. Importantly, Q4 production per share was the highest quarterly result in our history, a clear reflection of our quality of the combined asset base and the strength of our technical teams and processes.

For the year, we generated funds flow of $2.95 per share, one of the strongest on annual results in our history, despite operating in a lower commodity price environment. That speaks directly to the structural improvements achieved through scale synergy capture and disciplined execution. With capital expenditures in line with our $2 billion guidance, we generated approximately $900 million of free cash flow and returned $736 million to shareholders through dividend and $193 million through share repurchases. This balanced approach growing per share production while returning meaningful capital defines our total shareholder return framework.

In 2025, we delivered a 15% total shareholder return at the high end of our 10% to 15% target range. The return was comprised of 6% production per share growth, a 7% dividend yield and 2% of share repurchases. Our objective is to consistently deliver superior long-term returns through measured capital deployment, operational discipline and structural margin improvement.

From a reserves perspective, we now have 2.2 billion BOE of 2P reserves under management equating to a reserve life index of over 16 years with approximately 10,500 high-quality drilling locations in inventory that include optionality in light oil, liquids-rich and lean natural gas opportunities. With this, we have decades of development runway to continue driving increasing returns for our shareholders.

I'll now pass it on to Thanh to further discuss our financial results. Thank you.

Thanks, Grant. From a financial standpoint, 2025 clearly demonstrates the resilience and structural strength of our business. On a year-over-year basis, the commodity backdrop was weaker. WTI averaged just under USD 65 per barrel, down approximately 15% and AECO natural gas averaged under $1.70 per GJ.

Despite that environment, we generated funds flow of $2.95 per share, the second highest annual result in our history. More importantly, our cash flow netback increased year-over-year expanding margins in a lower price environment reflects structural improvements rather than commodity tailwinds.

There were 3 primary drivers: First, operating efficiencies. We accelerated the capture of synergies following the Veren combination. Field level optimization and economies of scale drove structural cost improvements with fourth quarter operating costs declining to $12.24 per BOE an 11% decrease from 2024.

Second, corporate and financing efficiencies, while G&A on a per BOE basis remained relatively consistent, we reduced absolute G&A through the elimination...

[Technical Difficulty]

New wells averaged roughly 10% above initial expectations in the area are supported by base optimization initiatives, including artificial lift refinements and operating parameter adjustments. Across our Montney assets, execution remains consistent, predictable and scalable.

At Musreau, we recently brought a 6-well pad online, bringing production to approximately 17,000 to 18,000 BOEs per day at 70% liquids. The facility is currently constrained due to stronger-than-expected condensate performance. Planned gas lift enhancements in Q3 of this year are expected to increase capacity to the 20,000 BOE per day nameplate.

Importantly, condensate performance at Musreau has translated into approximately 20% higher EORs than originally anticipated. And this is the result of our development design and production decisions made with this improvement in mind. In 2025, the asset generated over $100 million of operating free cash flow and is a good example of our repeatable development model, develop the resource, build infrastructure, optimize operations and transition the asset into a strong free cash flow generator.

At Lator, we drilled a 3-well pad in the fourth quarter and have recently spud a 5-well pad. A total of 11 wells will be spud this year ahead of the Phase 1 facility start-up. Construction of the 35,000 to 40,000 BOE per day facility remains on schedule and on budget with commissioning targeted for the fourth quarter.

At Kaybob in the Duvernay, we continue to drive efficiency gains as the asset progresses towards stabilized at capacity operations. Our wine rack development configuration is demonstrating improved reservoir access and reduced well interference. We have now brought 7 pads online using this configuration totaling 33 wells. Early pilot pads, some with approximately 18 months of production history, continue to affirm 10% to 20% improvements in well performance.

We are applying this configuration to approximately half of our 2026 development program and believe it is applicable across roughly half of our undeveloped inventory. Additional upside may come from further expansion of this approach and selective down-spacing where conditions are favorable.

With these improvements and continued base optimization, we now expect to reach debottleneck productive capacity of 115,000 to 120,000 BOEs per day in Kaybob by year-end of this year, well ahead of our prior expectation of the second half of 2027. This acceleration advances Kaybob into a stabilized free cash flow generating mode sooner than anticipated.

At $60 to $70 WTI, we expect asset-level free cash flow of $650 million to $850 million at capacity, while requiring only 50% to 55% reinvestment to maintain these levels of production.

Similar to Musreau, this transition from growth to stabilized mode reflects our broader development progression strategy, scale, optimize and harvest sustainable free cash flow.

With that, I'll now turn it over to Chris to discuss our Conventional assets.

Thanks, Joey. Our Conventional division delivered another strong year, averaging approximately 140,000 BOE per day in 2025. We invested $500 million and drilled 199 wells. The combination of stronger well performance and improved efficiencies drove approximately 3,000 BOE per day of production outperformance in the fourth quarter.

We continue to view the Conventional division as a stabilizing and sustainable core cash flow engine. The division is approximately 80% liquids weighted, primarily light oil and underpinned by a sub-20% decline rate. That decline profile is supported by roughly 52,000 barrels per day of dedicated waterflood and EOR production. This platform provides durable free cash flow and meaningful torque to stronger oil prices.

Saskatchewan was the primary driver of year-over-year growth as we solidified our position as the largest and most active oil producer in the province following the integration of the complementary Veren assets.

In the Frobisher, 2025 results were exceptional. Average IP 180 production exceeded expectations by 41%. These results reflect longer laterals, enhanced reservoir contact and continued operational efficiencies that improve capital productivity. Since entering the play in 2021, we have organically added nearly 200 premium locations, extending our runway by approximately 4 years. Compared to our initial type curve assumptions at acquisition, capital efficiency has improved by 26% based on IP 365 performance.

On a per well basis, that translates into materially higher net present value on approximately $1.6 million of capital per well. In the Bakken, we continue to enhance inventory through optimized lateral lengths and increased reservoir contact. Our first 3-mile 8 leg open-hole multilateral well achieved an IP(90) rate 38% above expectations, with a record 34,600 meters drilled. Based on these results, we are confidently incorporating extending extended reach open-hole multilateral drilling into our development program. With over 1,500 Bakken locations in inventory, we see substantial opportunity to further enhance well economics across this asset.

In Alberta, we drilled 39 wells primarily focused on the Glauconite and Cardium. The Glauconite continues to demonstrate strong repeatable performance and has evolved into a scaled, liquid weighted cash flow driver. Since acquiring the asset in 2021, we have doubled production from approximately 13,000 BOE per day to roughly 27,000 BOE per day through improved well designs, longer laterals, infrastructure, debottlenecking and base optimization. With scale achieved, the Glauconite has transitioned into a stabilized development phase generating consistent and capital-efficient returns.

In the Cardium, leveraging learnings from the Unconventional workflow, specifically on frac design, enhanced our performance in both West Pembina and Wapiti realizing improved capital efficiency by approximately 15% in 2025.

As we move into 2026, our focus remains on incremental technical enhancements to continue to improve capital efficiency. Finally, our EOR portfolio remains a cornerstone of sustainability within the Conventional division with approximately 52,000 barrels per day of dedicated secondary and tertiary production, including our flagship waiver and CO2 flood, we generate strong, stable cash flow from long life, low decline assets. We continue to evaluate additional EOR opportunities across the portfolio, assessing both brownfield and greenfield projects to further enhance long-term recovery and capital efficiency.

With that, I'll turn it back over to Grant for his closing remarks.

It's Thanh here. So I'll just redo the financial section here due to the technical difficulties before passing it back to Grant. From a financial standpoint, 2025 clearly demonstrates the resilience and structural strength of our business.

On a year-over-year basis, the commodity backdrop was weaker. WTI averaged just under USD 65 per barrel, down approximately 15% and AECO natural gas averaged under $1.70 per GJ. Despite that environment, we generated funds flow of $2.95 per share, the second highest annual result in our history.

More importantly, our cash flow netback increased year-over-year, expanding margins in a lower price environment reflects structural improvements rather than commodity tailwinds. There were 3 primary drivers: First, operating efficiencies. We accelerated the capture of synergies following the Veren combination. Field level optimization and economies of scale drove structural cost improvements with fourth quarter operating costs declining to $12.24 per BOE, an 11% decrease from 2024.

Second, corporate and financing efficiencies. While G&A on a per BOE basis remained relatively consistent, we reduced absolute G&A through the elimination of duplicative costs following the transaction. Our increased scale contributed to a credit rating upgrade to BBB flat, lowering our overall cost of debt and improving financial flexibility.

In addition, the utilization of acquired noncapital losses materially reduced cash taxes and enhanced free cash flow. Third, product mix and realized pricing resilience. Over 60% of our production is liquids, predominantly light oil and condensate, narrow differentials and foreign exchange tailwinds helped to offset benchmark weakness.

Turning to financial strength. Year-end net debt was $3.4 billion representing less than 1x annualized fourth quarter funds flow. We have $1.5 billion of available liquidity and remain well positioned to manage volatility. Approximately 25% of 2026 oil production is hedged a floor of just under CAD 85 per barrel and 29% of 2026 natural gas production is hedged at approximately $3.75 per GJ. On natural gas diversification, we are executing a deliberate strategy to reduce long-term AECO exposure. We announced a 10-year agreement with Centrica for 50,000 MMBtu per day indexed to European TTF pricing and a second 10-year agreement to deliver 35,000 MMBtu per day into Chicago at Henry Hub pricing. These agreements enhance price stability and increase exposure to global and U.S. markets.

I'll now pass it off to Grant for his closing remarks.

Thanks, Thanh, Chris and Joey for your comments. In closing, we believe we are still in the early stages of demonstrating the full capability of our asset base and the people we have within the organization. Operational momentum has carried into the first quarter of 2026, and our teams are executing at a high level across our portfolio.

As a result, we are providing first quarter production guidance of 375,000 to 380,000 BOE per day, which is up from our internal forecast of 370,000 to 375,000 BOE per day at the time we released our budget. Our full year production guidance of 370,000 to 375,000 BOE per day on capital spending of $2 billion to $2.1 billion is unchanged at this time, but stay tuned as we advance through the remainder of the year.

With scale achieved, structural profitability improved and a deep inventory of high-quality opportunities, we are confident in the path forward to deliver superior returns for current and future shareholders. Improving market access for Canadian energy remains an important theme for maximizing economic value and strengthening North American energy security. Condensate fundamentals remain supportive and expanding LNG and natural gas demand continue to provide long-term tailwinds.

In closing, I want to reemphasize that our team remains focused on disciplined execution, efficiencies in capital spending and deliberate in creating superior long-term returns for our shareholders.

With that, I will now turn the call back over to our operator, Sylvie, for any questions. Thank you.

[Operator Instructions]. First will be Sam Burwell at Jefferies.

Grant, I caught your stay tuned on the 2026 plan. So I guess with WTI strip up near USD 65 for the balance of '26, any appetite to possibly hedge more and/or deploy more CapEx maybe in Conventional oil or should we think about any benefit to cash flow really being banked for possible buybacks going forward?

Yes. Thanks, Sam. Just your comments on what we do with the increased pricing at this particular time. You know the strategy that we've undertaken is that until we have it, we'll call it, in the bank, we don't make adjustments to our forecast. We are forecasting for the balance of this year, USD 65 WTI oil with a light oil differential at $4, $2 differential on condensate and CAD 0.74. And what we've done with our natural gas price, we dropped it back to $2 per GJ just with the -- what we consider to be the oversupply. So at this particular time, what we'll look to do as we advance through time here is the potential to increase our forecast with the same amount of capital if we can continue to deliver operationally as we have.

Yes. And Sam, just on the hedging front there. I mean our strategy hasn't changed. We look to hedge 25% to 35% of our production here and feel very comfortable around our 2026 positions as I've talked about there. What we are doing, though, is we're laying on more positions in 2027, smaller incremental positions to get us to that 25% to 35% there. Since the curve is still a little bit backward dated, our preference today is using costless collars. So that's been a very consistent theme in terms of how we've executed on our hedging strategy.

Okay. Understood. And then on the gas marketing side, I guess, any color you can share on the discount to TTF you'd be realizing on the Centrica deal? And then also on that, like how repeatable are the opportunities to achieve LNG linked pricing without necessarily like explicitly sending molecules to a facility, whether it's in Canada or whether it's down to the U.S. Gulf Coast?

Yes. Thanks for that question, Sam. So the 2 contracts that we entered into are part of our price diversification strategy we're really taking a portfolio approach to mitigate the price volatility that we've seen in the AECO market there. Ultimately, what we're looking to do is move about 50% of our pricing outside of AECO. And with these 2 contracts here, we would be increasing our exposure outside of AECO in that 8% to 9% there. So the Centrica transaction, we basically get the TTF pricing less deductions. We deliver at AECO. And with the other third party there, the 35,000 MMBtu per day there the delivery is at Chicago. So we get NYMEX basically less tolls there. But we don't disclose any specific details to our contracts.

Next question will be from Phillips Johnston at Capital One Securities.

I wanted to ask you about the current tax rate guidance for '26. Nice to see that you reduced it to 3% to 5% of funds flows from I guess, 5% to 8% previously. I realize Veren had some tax loss pools that might be playing a factor. But can you talk about what's driving that? And as we look out over the next 4 years or so, I assume that percentage will drift higher. But can you maybe talk about sort of the glide path there?

Yes. It's Thanh here. So in terms of the tax pools at the end of the year, we had $9.3 billion of tax pools, of which approximately $500 million of that was noncapital losses. And so we were able to use -- when we did the Veren transaction, it came with about $1 billion of noncapital losses. So we used about half of that in 2025. And then the remaining $500 million, we expect to use that in 2026. So that's really what drove the lower tax rate there in that 3% to 5%. So pretty consistent, I would say, in 2026 compared to 2025. As we think about it going forward here, we'd expect it to be still pretty reasonable in that 5% to 8% on a go-forward basis past 2026.

Okay. Great. That sounds good. And then your proved developed producing F&D costs ticked up a little bit from around $15 a barrel back in '23 to around $17 a barrel in '25. That's obviously a low figure still. But can you maybe talk about the driver of the increase there? Is it perhaps related to sort of a mix shift within the portfolio rather than any sort of increase in D&C costs or decrease in underlying EORs? Or are there other factors at play? And then just maybe as a follow-up, how would you expect those costs to trend going forward?

Phillips, Joey Wong here. So yes, you're right that the $17 and change there is a reflection of the asset mix when you combine Veren and Whitecap. And the -- it actually does reflect on PDP as well as across the other 2 categories on the 1P and the 2P. A portion of the efficiency gains we've started to see in the operations whether that's on the reduction of cost, taking a portion of those on the book or on a portion of the increased performance on a per well basis where we did see some good technical revisions.

To your question of what would the trajectory of that be? I guess it's embedded in the last response there is that we've taken a portion of it, and we would expect that with continued performance and outperformance that we can build upon that.

[Operator Instructions]. Next, we will hear from Michael Spiker at HTM Research.

I'm not sure if the cut out there was intentional, give everybody a few minutes to reflect on the pure unbridled execution that we're witnessing. But in my few minutes looking through the deck, I see you guys have 90,000 BOEs a day of asset potential in the near-term, productive capacity bucket. And you don't consume that until the early 2030Shelf Drillin. So you've got all these efficiencies that you're realizing and you can kind of move some of that infrastructure CapEx over to PGI potentially. Is there a possibility to -- when you have that money in the bank, you said to maybe keep growth capital flat and add more volume kind of thing if you keep delivering sequential capital efficiency improvements? Just kind of wondering, could we see a filling of this 90,000 BOEs a day of near-term capacity from the debottlenecking efforts, et cetera, pulled forward a little bit on the same capital budget kind of thing? Is that kind of a potential upside we can think about?

Yes. Thanks, Michael. I mean, so the way we're thinking about this is, obviously, yes, we do have the capacity runway through to an incremental 90,000 BOE per day. A lot of this reflects back on what the commodity price environment is of the day. So from our perspective, we think that we can continue to focus on our efficiencies of our capital program. But growing into this, the opportunity base that we do have is truly going to be what's the reflection of commodity prices and the cash generation that's being delivered off of the assets we do have. So I appreciate you realizing that we do have a lot of runway in front of us at this particular time, but it is going to be dependent upon commodity prices as we advance forward. We think we've got a very sound base plan in place and then being able to continue to grow into the excess capacity that we do have available to us.

Thank you. And at this time, gentlemen, we have no other questions registered. Please proceed.

Okay. Thank you, Sylvie, and thanks to each of you on the line today for your patience and with the technology glitch we experienced earlier. I do want to once again thank our entire Whitecap office and field staff for your dedication and efforts in 2025 and continuing into 2026.

We look forward to updating you as shareholders on our progress through 2026 and into the future. All the best to each of you 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. And at this time, we do ask that you please disconnect.

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 Investor Day. [Operator Instructions] And I would like to turn it over to Whitecap's President and CEO, Mr. Grant Fagerheim. You may begin the conference.

Thanks, Sylvie. Good morning, everyone. We are excited to walk through our asset base, the work our technical and support teams have been doing and why we're confident into the future with the opportunities we have in front of us. I am joined today with -- by 6 members of our management team. Thanh Kang, our Senior Vice President and CFO; Joel Armstrong, our Senior Vice President, Production and Operations; Dave Mombourquette, our Senior Vice President, Business Development; and Information Technology; Joey Wong, our Vice President, Unconventional Division; and Chris Bullin, our Vice President, Conventional Division; and Travis Tweit, our Vice President of Operations.

Before we begin, a quick reminder that today's discussion includes forward-looking information and all statements are subject to the same forward-looking disclaimer and advisory contained in the Investor Day presentation, which we have posted on our website. So let me start with what we're going to cover today.

First, I'll walk through a high-level overview of Whitecap, including how we think about capital allocation, leverage and an overview of our portfolio. From there, we'll move into the assets and what we're excited about to continue developing and improving our -- both our design and execution across our business. Let's put the asset discussion into 2 major parts. Joey Wong will lead the Unconventional section. Chris Bullin will lead the Conventional section, and Travis Tweit will highlight our operational achievements across both divisions.

In the Unconventional Section, the focus will be our inventory depth, duration and optionality we have across commodities, including illustrated project scenarios that highlight economics and flexibility. In the Conventional section, the focus will be on asset stability and longevity and maximizing resource capture across our light oil weighted portfolio. We built a proven platform, and we believe these assets can continue delivering strong profitability and value creation for decades to come. And finally, I'll walk through the growth optionality and asset potential we see across our full portfolio over the next several years before wrapping it up and opening the line for questions, both through the webcast and by phone. With that, we'll get into the presentation.

At the highest level, our strategy is straightforward. We allocate capital with one purpose to generate strong, durable returns for shareholders. Today, we want to show you how -- why Whitecap stands out not just compared to other energy companies, but also compared to alternative investments more broadly. Our advantage comes down to 4 things: high-quality inventory with both depth and commodity optionality, technical excellence and strong execution, capital discipline to protect and compound shareholder value and a strong balance sheet to manage risk and stay flexible through cycles.

First, on inventory. Our depth and optionality gives us confidence in our ability to generate consistent, meaningful returns even through commodity price cycles. But inventory alone is not enough. The profitability of any energy asset depends on how well we drill it, complete it and operate it. That's why we believe our technical and operations teams provide us with a core competitive advantage and they continue to finding ways to improve well performance and reduce costs across all areas of our business. And finally, capital discipline and balance sheet strength are what allow us to manage risk, protect shareholder value, and stay counter cyclical, especially when additional opportunities emerge in the market. Those 4 pillars, inventory, execution, discipline and balance sheet are what drives Whitecap strategy.

With that, we'll now get into the presentation. For those of you who may be newer to the Whitecap story, here's who we are today. We are a $14 billion market cap company with $17 billion of enterprise value. We produce about 372,500 BOE per day, making us the seventh largest Canadian oil and natural gas producer. On the natural gas side, we produce 900 million cubic feet a day, which ranks us the fifth largest gas producer in Canada. In 2026, we plan to invest between $2 billion to $2.1 billion in capital at $60 WTI and $3 AECO price, that generates approximately $3.3 billion of funds flow. Our balance sheet remains very strong with $3.3 billion of net debt, which was only 1x debt to funds flow. And we pay a $0.73 per share annual dividend representing a yield of just over 6% to 6.5% at today's share price.

Why own Whitecap? Our goal is simple: to deliver meaningful shareholder returns through both per share value growth and consistent return of capital. Our annual target is to provide -- our annual target is to provide a 10% to 15% annual total return to shareholders. And on the next slide, we'll walk through how we plan to do that. These returns are powered by the asset base that we built over the last 16-year period of time. It is long duration, high quality and offers real commodity optionality across both our conventional and unconventional assets. Today, we have 10,500 drilling locations in inventory and 2.3 billion BOE of 2P reserves. That's our foundation for delivering returns sustainably over the longer term.

Equally important is our balance sheet. We operate with investment-grade credit. We target leverage of 1x or under, and we run a fully funded model, which gives us flexibility and resilience through the cycles. And finally, scale matters. We invest roughly $2 billion per year in capital and $1.5 billion per year in operating costs. This stability of capital allows us to secure preferred crews, rigs and pricing. As the seventh largest Canadian producer, and the largest landholder in the Alberta Montney and Duvernay, our scale creates efficiency, improves execution, strengthens margins and ultimately improve shareholder returns.

Our capital allocation toolkit. Although we begin our journey -- we began our journey in 2009 as a growth-only entity, Whitecap has been running a dividend plus growth model since 2013. And what we've learned is that strong shareholder returns aren't driven by one single mechanism. They come from having a disciplined toolkit and optimizing it through ever-changing price cycles. Our toolkit is built around 4 levers. Investing in the business when the return is available and there, maintaining balance sheet strength, share repurchases and our dividend. We have assembled an outstanding asset base and using the asset base to generate more free cash flow is one of the best ways to create long-term value for shareholders. While the market may not be calling for growth today, our portfolio is positioned to generate high return growth when price returns, and we will remain disciplined about this.

Balance sheet strength has been central to Whitecap success. Low leverage gives us the ability to weather downturns. But just as importantly, it allows us to take advantage of opportunities that others can when the time is appropriate. That is how we built much of our Montney and Duvernay position, including funding the XTO acquisition in 2022 with all cash and taking on Veren's higher leverage company in 2025. And since then, we've driven down costs, improved overall execution and increased profitability, all of which have translated into stronger shareholder returns. On share repurchases, we prioritized using this tool when our share price is below intrinsic value and our after-tax cost of debt is lower than the cost of equity.

And we like buybacks because they permanently strengthen the capital structure and improve our payout ratio. Finally, our base dividend is foundation, stable and meaningful at $0.73 per share annually. Over time, our plan is to grow the dividend as well. But given where our payout ratio is today, we expect incremental return of capital in the near term to be more weighted towards share buybacks.

Counter Cyclical approach. How do we deploy capital across the toolkit, depends primarily on commodity prices and where we are at in the pricing cycle? This slide shows how our priorities shift through different commodity environments. The key point is our ability to be counter cyclical coming from 3 advantages: low leverage and a strong balance sheet, high-quality, long-duration inventory in both light oil and natural gas and a low decline, low-cost structure that generates free cash flow across all points in the cycle. With these attributes, we have the flexibility, which allows us to consistently generate long-term returns.

Now I want to be clear. This slide is illustrative. We are not formulaic. At any given time, the right decision depends on the valuation, commodity price direction, operational constraints and market opportunity. But the concept is straightforward. In the lower price environments, as we are in now, there's usually no market call for growth. The priority becomes maintaining base production and returning excess funds flow through share repurchases, especially if shares are trading below intrinsic value. As prices rise towards mid-cycle, we reinitiate growth and balance shareholder returns between buybacks, dividend and balance sheet strength.

When prices move above mid-cycle and economic supported, growth goes higher in priority, still within our corporate growth range of 3% to 5% per share and excess funds flow is directed towards strengthening the balance sheet and building dry powder for future opportunities. Again, we won't be rigid with this strategy, but instead adaptive to the prevailing market conditions. This framework helps investors understand how we think about allocating excess free funds flow through the commodity price cycle. With this, I'll pass on to Thanh for a quick discussion on our balance sheet. Thanh?

Yes. Thanks, Grant. We entered 2026 with a very strong balance sheet, low cost of funding and approximately 50% of our net debt at a fixed interest rate. We're comfortable with the current mix, but if rates continue to trend favorably, we could potentially look to add additional fixed rate debt to further enhance stability. In 2026, we plan to use room on our credit facility to address the private placement notes maturing that year. Beyond that, we have 4 issuances of investment-grade notes with maturities spread between 2028 and 2034. Our most recent bond issuance was at 3.76% and our variable cost of debt on the credit facility is around 4%. Overall, our debt costs remain very reasonable and contribute to our low cost structure. You may see quarterly fluctuations in net debt due to the seasonal nature of our capital program.

But given our strong balance sheet and the current commodity environment, our focus is on enhancing shareholder returns, particularly through share repurchases rather than aggressively paying down debt today. Over time, as prices increase, we expect to focus to -- we expect the focus to shift towards reducing leverage further and building additional dry powder for future inorganic opportunities. And to maintain flexibility, we will continue targeting 1x debt to funds flow or less.

Slide 10 shows the evolution of the business over time. In the earlier years, we were comfortable running higher leverage while we built the company. But over the last several years, especially through acquisitions like NAL, TORC, XTO and most recently, Veren, we've made a deliberate shift towards maintaining leverage at approximately 1x. That discipline is what allowed us to execute the Veren transaction and absorb their higher leverage while still maintaining a strong credit profile. Looking forward, we expect leverage to continue trending down over time as we build free funds flow and maintain disciplined capital allocation. And with that, I'll pass it back to Grant to close out on the introductory slides.

Thanks, Thanh. Asset overview. All of our assets are located within Western Canadian Sedimentary Basin, with over 99% of our production and inventory in Alberta and Saskatchewan. We have significant inventory depth with decades of drilling inventory at our current pace. We divide the business into 2 primary groups: First, our unconventional assets Montney and Duvernay. These are high rate, high reserve resource style developments with 4,700 drilling locations in inventory and a significant growth in free cash flow potential. Second, our conventional assets across multiple regions and formations primarily focused on light oil. These assets include long life, low decline production and enhanced oil recovery projects. They generate stable, durable cash flow and provide long-term sustainability for the business. Overall, our commodity mix today is approximately 50% light oil and condensate, 10% liquids and 40% natural gas.

In Slide 12, our development progression. Slide 12 shows how we think about development progression across our portfolio of opportunities, along with the maturity of assets within each division. The key point is this. Not all inventory is meant to do the same job at the same time. We deliberately segment assets into 3 categories: appraisal and delineation number one; number two, growth; and number three, stabilized assets. Each category plays a different role in our team's focus on maximizing value as assets move along the progression. Appraisal is about replenishment and long-term sustainability. Growth assets are where we drive our 3% to 5% production per share growth annually and stabilized assets generate significant free cash flow, supporting dividends, buybacks and balance sheet strength. The majority of the makeup of our conventional assets fall into the stabilized category, but that does not mean that they're near end of left.

These assets are well understood, remain highly profitable, and we have decades of runway with meaningful upside that we'll talk about later in the presentation. Our conventional assets are balanced across 3 categories, and they contain the asset -- projects that will contribute most to our long-term growth. A great example is Kaybob Duvernay play. It has progressed rapidly through growth stage and is nearing current capacity. Through debottlenecking of our 15-07 complex, we've increased capacity and we're positioned to transition to stabilize strong free cash flow developing asset. And we're especially excited about that, given the inventory enhancement we made through our Winerack development initiatives. Across the remaining growth in appraisal categories, we have inventory across the commodity spectrum, and we'll highlight the optionality and future potential throughout the rest of today's presentation.

I'll now pass it off to Joey Wong to walk through our Unconventional division. Joey?

Thanks, Grant. Now we'll transition into the unconventional division, where we see some of the strongest long-term growth and free funds flow potential in our portfolio. There are 3 key takeaways from this section. First is inventory depth. This division holds the largest share of our long-term growth runway. Second is technical improvements. We've made meaningful progress in development planning and execution, and that progress continues to compound. And third, commodity optionality. We have a portfolio that gives us flexibility across light oil and condensate, liquid rich gas and lean gas, and we can scale that activity based on market signals. This slide highlights the scale and quality of our unconventional asset base. We hold approximately 1.5 million acres of Alberta's Montney and Duvernay, and that makes us the largest landholder in both plays. The division produces roughly 245,000 BOEs per day and delivers approximately $900 million of annual free fund flow at $60 WTI and $3 AECO. And importantly, the assets are concentrated, which drives efficiency, repeatability and cost control. That concentration is a key advantage. It improves execution and supports stronger margins.

Slide 15 shows our unconventional type curves and the quality of the inventory across the portfolio. We have a high-quality, scalable inventory across the commodity spectrum, and that gives us flexibility and resilience through the cycle. At one end, we have the light oil and condensate growth options where liquids pricing and condensate yields create very strong margins and attractive returns. The oil and condensate window is defined as greater than 250 barrels per million standard cubic feet of natural gas on an IP90 basis. On the other end, we have lean gas assets and these are important because they represent a long-dated growth lever.

Lean gas becomes very competitive in stronger gas price environment, and we've positioned those assets so that we can scale efficiently when gas prices justify it. Lean window is defined as less than 50 barrels per million. And in between, we have liquids-rich gas opportunities. These deliver strong rates, strong economics and fast payouts. What we want you to take away from this slide is that our unconventional portfolio isn't tied to one commodity outcome. We can allocate capital to the projects with the best returns at the time and that flexibility is one of the reasons we believe we can deliver durable shareholder returns through the cycle. The other advantage here is that we've been able to improve these type curves through design and execution, which will show later in the section. These are not static assets. Our teams are actively improving performance.

Moving into more detail. Let's start with the Duvernay position in Kaybob. The Duvernay is one of the premier unconventional resource plays in North America. And for Whitecap, it's a major value driver because it combines scale, strong well performance and a near-term pathway to significant stabilized free funds flow. We're the largest landholder and operator in the Duvernay with approximately 500,000 acres and about 700 identified locations. Roughly half of that inventory is liquids rich with another 40% weighted to light oil and condensate. With over 500 producing wells, we operate roughly the same number of Duvernay wells as the next 2 operators combined. That scale delivers real advantage, operating efficiencies in the field and equally important, one of the strongest proprietary data sets in the play.

It drives better development planning, sharper execution and ultimately, superior economics and returns. Geologically, our Kaybob Duvernay position has some of the most favorable characteristics for development. The reservoir is thick, laterally extensive, overpressured and predominantly liquids rich or condensate prone. Porosity is predictable across the area and while thickness varies across the land base, we adjust our development plans accordingly. Where we see greater thickness, we've moved toward Winerack style development to improve vertical reservoir coverage and reduce interaction between wells. Where thickness is more limited, we widen inter-well spacing and utilize longer frac half length to enhance capital efficiency and maximize value per well. We'll speak to these design choices and the resulting performance in more detail in the coming slides.

When we first entered the Duvernay in 2022, we were excited about the runway in front of us, supported by our owned and operated 15-07 gas plant, which at the time was only 50% to 60% utilized. As development progressed and results continued to improve, it became clear that we were approaching the facility's capacity limit, one that would have been reached in 2025 as our development initiatives continue to bear fruit. To create additional runway and enhance economics, our team increased the productive capability of the 15-07 complex through a combination of facility debottlenecking and the construction of a connection to a third-party processing facility. This work increased the productive capability of the complex to over 50,000 BOEs per day, an increase of over 40% from the original productive capability of approximately 36,000 BOEs per day.

This additional capacity not only supports our development plans, but it also drives a structural improvement in netbacks with operating costs expected to decline more than 30% as we approach capacity. We expect the final stage of these efforts to come online in early 2026. Following further debottlenecking and expansion on the north side of the asset, the Kaybob Duvernay is expected to reach total processing capacity of approximately 120,000 BOEs per day by the third quarter of this year. Once we achieve that capacity, our intent is to hold production in the 115,000 to 120,000 BOE per day range longer term and transition Kaybob away from the growth phase and into a stabilized at capacity mode, as Grant mentioned earlier. At that stage, Kaybob is expected to generate approximately $650 million to $850 million per year of asset level free cash flow while requiring only 50% to 55% reinvestment to maintain flat production, providing a significant source of sustainable free cash flow to the corporation. This is exactly how we think about asset development, scale the resource, optimize the infrastructure, debottleneck constraints and then transition into a stabilized free funds flow phase where cash flow can then be returned to shareholders.

Next, we'll turn to the Montney, which offers one of the deepest sources of long-dated organic growth in our portfolio with development opportunities across the full commodity spectrum from light oil and condensate to liquids-rich and again lean gas. Slide 21 provides an overview of our Alberta Montney position, which, as mentioned at the outset, is the largest by landholdings with approximately 1 million acres. This is a large, high-quality asset base with meaningful existing infrastructure, and it provides several distinct development options with a mix of light oil and condensate, liquids-rich gas and lean opportunities. This is important because it gives us optionality. But we want to be clear, development will remain disciplined. We will scale activity only when returns justify and within our broader corporate capital allocation framework.

So the Montney is both an opportunity set and a tool. It gives us a way to respond to commodity price signals while maintaining capital discipline. The Montney is a thick, stacked and highly predictable resource with meaningful commodity diversity, making it increasingly attractive to both investors and operators seeking premium long-dated inventory. We have strong visibility across multiple benches, supported by extensive 3D seismic coverage and a large data set of industry and operated wells, enabling us to extract significant proprietary insights, mirroring the same advantage we've built in the Duvernay. Targeted horizons are shown in blue, while zones currently being delineated are highlighted in green dashed. Many of these horizons, both blue and green dashed remain unbooked, emphasizing the material upside potential still embedded across our land base.

Over the next few slides, we're going to walk through some development projects that illustrate the optionality and profitability potential we see across our asset base. These projects are at various stages of technical due diligence and appraisal, but to demonstrate the capability of our teams and the quality of the assets, we'll start with a case study of our most recent development at Musreau, a great proof point for how we create value through execution. When we set out to build the 05-09 facility, we took the time to ensure the facility size and design were properly matched to the inventory. We sanctioned the project with an expected payout of approximately 3 years. Fast forward to today, the facility has come in under expected cost and ahead of schedule, and our development decisions have driven 10% to 20% well outperformance. As a result, realized payout has improved to well under 2 years. Now that the asset is operating in a stabilized state, Musreau is generating approximately $90 million to $115 million per year of asset level free cash flow. And similar to what you saw in the Duvernay, we're reinvesting approximately 50% to 60% to hold production flat. This slide is important because it demonstrates the repeatable playbook, develop the resource, build the infrastructure, lower costs, improve margins and transition into strong free funds flow generation. That's how we position these assets to become durable return engines.

Slide 24 is an update on the LATOR Phase 1, our next material growth project anchored by our Phase I facility at 04-13. Phase 1 is a 35,000 to 40,000 BOE per day facility sanctioned in 2024. We were fully permitted ahead of schedule, which enabled us to accelerate our commissioning time line. Construction is well underway, approximately 50% complete on a spend basis, and we're targeting commissioning in Q4 of 2026. We have approached LATOR with a disciplined and methodical development strategy focused on optimizing outcomes while managing key risks. Derisking has been central to our work, and we've executed that in 2 areas: the facility and the assets. First, the facility. The design leverages 2 similar facilities we've built and operate today in Kaybob and the one I just mentioned in Musreau, both of which were commissioned successfully and have delivered strong operating performance. LATOR incorporates design enhancements informed by that operating history with a focus on proactive debottlenecking, improved operability and long-term efficiency.

The facility has also been engineered around the expected product stream, which brings me to the second point, which is the asset. After several years of study and delineation, we have a strong understanding of the subsurface, particularly across areas that will support near-term drilling. We benefit from a meaningful legacy data set, including roughly 2 dozen horizontal wells plus 7 Whitecap horizontal drills and a vertical core. We also hold 3D seismic coverage over nearly 100% of the land and have built robust geological, geomechanical and reservoir models to forecast reservoir and frac behavior. Our existing wells have met or exceeded expectations and the majority of our technical work, including the core data, has been confirmatory or to the positive. Despite these positive data points, we have maintained our expectations to ensure we remain disciplined and avoid overstating asset capability ahead of full-scale development. This is a clear example of how we pursue growth. Methodically, rigorously and with risk-adjusted execution, it will continue to -- and it will continue to define our approach as we progress through subsequent development phases.

Over the next 3 slides, we're going to walk you through illustrative characteristics for 3 project types we see as core to long-term organic growth in our unconventional portfolio. Everything shown here assumes no improvement in capital efficiency. So the outcomes reflect today's design and execution baseline, even though we have a strong track record of continuous improvement. Across the 3 project types, we're outlining over 365,000 BOEs per day of productive capacity supported by identified inventory within the 4,700 unconventional locations discussed earlier.

This slide focuses on the liquids portion of the portfolio, and we're using LATOR Phase 1 as the example given it's already under construction. The top left is net operating income per unit of capital invested. The 1.0 line would be payout. Under base pricing, which is $60 WTI and $3 AECO, payout occurs in roughly 9 to 12 months. The 2 sensitivity cases either an increase in AECO of $1 or $10 in WTI, those increased net operating income by roughly 10%, highlighting strong leverage to commodity pricing improvement. On the right, we show the transition from the build phase into stabilized production. We expect LATOR to become a cash contributor by 2028, with run rate free cash flow in the range of $170 million to $200 million and reinvestment ratio of 50% to 55%. It takes roughly 50 to 55 wells to reach facility capacity. And once there, we can hold volumes flat with only a couple of pads per year.

With 300 to 450 wells identified feeding the area, we have decades of inventory to work with. We've also built in design optionality for a Phase 2 expansion to 85,000 BOEs per day should market conditions warrant. Lastly, we know Kakwa also has a 40,000 BOE per day future growth project, which is a very compelling growth asset under the right conditions. It has extensive industry data, a thick reservoir with up to 3 benches of development and our performance across those benches has exceeded expectations. Today, it is infrastructure constrained and has sour gas considerations, but with access to centralized sour capable processing, it would compete for capital at the appropriate time.

Next, we'll turn to our light oil and condensate weighted growth options, starting with Gold Creek. This project would add approximately 25,000 BOEs per day of incremental productive capacity in the Gold Creek area. Again, the base case type curve is shown in blue. And on a normalized basis, the returns are highly comparable to the liquids rich project we just discussed on the last slide, within 2% to 3%. In other words, capital deployed into these projects is effectively equivalent from a return perspective. The key differentiator is commodity leverage. On the light oil-weighted side, returns demonstrate greater upside sensitivity to oil prices, which is roughly a 15% improvement in normalized returns compared to just over 5% uplift from higher gas pricing. We expect run rate free cash flow in the range of $190 million to $230 million per year, which is similar to LATOR Phase 1 despite being -- despite lower BOE volumes driven by stronger netbacks. Importantly, our technical confidence in Gold Creek has materially improved since adding it through the Veren transaction, and we're excited about the development runway ahead. The takeaway here is straightforward across our light oil and condensate weighted growth options we see multiple pathways to material free cash flow generation with returns that are fully competitive with our liquids-rich gas growth opportunities.

Lastly, we'll turn to our lean gas growth options concentrated in Resthaven, a core source of long-dated portfolio optionality. Resthaven is a large, contiguous land position of approximately 350,000 acres with over 1,000 identified drilling locations. To put that in context, Montney development in the Kakwa strike, which has seen significant industry development for many years, spans roughly 200,000 acres. We operate approximately 2 dozen horizontal wells across this land base, supported by additional industry offsets and targeted 3D seismic. That data set, both proprietary and public has enabled the rapid technical progression similar to the learning curve we have achieved at LATOR.

Our work indicates a meaningful portion of the asset exhibits high-pressure, prolific lean gas behavior with strong initial gas deliverability and associated condensate. As shown in the type curve, base case payout is approximately 1.3 years at $3 per GJ AECO and the returns are most sensitive to gas pricing. Importantly, at higher AECO pricing within the range shown on the slide, Resthaven competes directly with our liquids-rich and condensate weighted growth option on a normalized basis. From a development standpoint, scaling Resthaven will ultimately require material gas processing capacity. However, we're not forcing that decision today. Instead, our focus is on disciplined appraisal-driven execution. In 2026, we plan to drill 2 delineation wells to validate the translation of legacy results into modern development designs. With success, we'll expand appraisal across additional portions of the land base before advancing a phased facility concept.

An initial development phase, we target approximately 40,000 BOEs per day of productive capability supported by 200 million to 250 million a day of gas handling and associated condensate volumes. At higher gas prices, this phase would generate meaningful free cash flow while preserving significant upside for future expansion. And again, as mentioned at the outset, the core message here is optionality. Resthaven is long-dated, scalable and supported by identified inventory that could ultimately enable growth towards 200,000 BOEs per day, and we're positioning the assets so it's ready when market conditions warrant.

The next few slides focused on how we design and execute our capital programs. We expect to continually improve capital efficiencies across the portfolio, and that's driven by what we call our unconventional development workflow, a collaborative process that has delivered exceptional results across our unconventional plays and will continue to do so going forward. The upside from this workflow is what drives improvement across the metrics shown on the prior slides.

Now to walk through the figure. First is subsurface evaluation. We integrate geological, geomechanical and multiphase reservoir models to understand the rock, fluids and expected stimulation and production response. Next is the development plan. That work drives optimized decisions on well spacing, bench selection and completion design balancing value and risk. Following that, economic evaluation. We evaluate risk-adjusted returns across commodity scenarios using engineering analyses and in-house machine learning tools to identify patterns and optimization opportunities across large data sets. Lastly, execution and iteration. We execute consistently and efficiently through tight cross-functional coordination and we iterate quickly as new data is gathered. The key point is that the workflow is continuous. Every new data set feeds back into the system, refining designs, improving performance and upgrading inventory over time. As you'll see next, the process has already delivered measurable gains, which are embedded in our 2026 capital efficiencies and guidance.

As mentioned, the next few slides show how that workflow translates into real measurable improvements. This slide focuses specifically on design optimization, where the architecture of the development plan sets us up for optimal returns before we commence operations on the land. I'll walk through 3 examples. First, Montney upspacing at Kakwa. Based on early well results and offset operator data, we saw indications that with modest changes to completion design, we could reduce well density without sacrificing recovery. We tested that hypothesis through 2 pilot pads moving from 8 wells per spacing unit down to 6. The results confirmed our expectations. On an acreage basis, recovery was effectively unchanged, but with materially less capital deployed, a clear improvement in capital efficiency and returns.

Next, we're profiling the benefits of benching and drawdown management at Musreau. In this area, we observed similarities to Kakwa and believe that the development plan could be further optimized on our lands by moving to a 2 bench development design and importantly, by controlling drawdown, the pace at which we allow the reservoir to produce into our facilities. With both design features in place, we saw a shallower decline in condensate to gas ratio relative to offset. The result is what you see in the middle graph, and improvement in our condensate production profile. While our wells were below offset wells on initial rates during the first 5 to 6 months, the disciplined development plan and controlled drawdown have allowed us to outperform later in life. At this stage, we are comfortable underwriting a 20% improvement in condensate EUR. Importantly, this is fully backstopped by an economic analysis to ensure we are improving returns. In this case, payout was effectively equivalent as what we gave up early with gain back in the subsequent months.

The third example of design optimization is in the Duvernay, where we've applied a similar concept to the Musreau benching design, but more modestly and within the same bench to what we refer to as a Winerack design. With only approximately 50 meters or just under 50 feet of vertical offset, we've achieved better vertical coverage in the reservoir and reduced well-to-well interaction, both between wells on the pad and to offsetting wells. The cross pads where we have sufficient production history, we've observed a 10% to 20% improvement in well performance and are now evaluating further optimization opportunities including the potential to down space within our existing inventory set to better capture acreage value.

The key takeaway is that these are not just the theoretical games. They're observed, repeatable and embedded in our forward plans, as I mentioned. This is importantly, they reflect our disciplined approach to improving returns without introducing corporate -- material corporate level risk. With that, I'll turn it over to Travis Tweit, Vice President of Operations, to speak to the execution improvements we've realized across these programs.

Thanks, Joey. The next few slides highlight examples of the improvements we've delivered in drilling and completions across the Duvernay and Montney and importantly, how repeatable these results are when we run consistent programs. I'll also share a recent example of base production optimization and show how the internal workflows Joey discussed, translate into best in class completion design and execution. Starting with drilling. As you can see, we made some measurable progress across several core areas. At Musreau, we've had a continuous program since 2023 using the same drilling rig and our overall rate of penetration has improved by 30% over that time.

By leveraging the data available from neighboring wells, we were able to achieve today's ROP after only 20 wells drilled, a level that offset operators requiring closer to 150 to reach. We're now taking those same learnings from Musreau and applying them directly to LATOR as development begins there. The middle chart shows drilling performance at Gold Creek, where we realized an average 8% improvement in ROP in the back half of '25. This is an area that has seen steady improvements from legacy operators, which has helped to refine our drilling designs and improve execution performance. Gold Creek is a really good example of how strong performance becomes repeatable once an area is in development mode, where recent gains tend to be more incremental, same high-performing rig and services, consistent crews and continued reductions in flat time driven by our drilling teams.

The chart on the right highlights performance in the Kaybob Duvernay achieved primarily through adopting best practices from both legacy Whitecap and Veren operations. These improvements include minor adjustments to drilling practices and small changes to BHA design, resulting in improved tool reliability and fewer trips in the lateral. Combined with using fit-for-purpose rigs and maintaining consistent services, these changes have delivered a 13% improvement in ROP as shown here. And while we're pleased with the progress we've made, we're still very much on a path of continuous improvement, focusing on every marginal gain through reducing flat time, leveraging technology and continuing to refine our processes.

I'll now switch to completions. With completions representing nearly 50% of our unconventional spend, we maintain an intense focus on both efficiency and effectiveness, meaning how quickly we execute and how well the fracs perform. I'll speak to effectiveness on the next slide. This slide focuses on efficiency, measured as tonnes of proppant pumped per day. As you can see, performance has improved substantially in the back half of 2025. Starting on the left with Musreau, this has historically been a plug-and-perf area for Whitecap. Over the past 2 years, we've continued to refine workflows and execution discipline, resulting in a 14% improvement in efficiency to an average of around 3,600 tons per day.

The middle chart shows Gold Creek, which has primarily been a single-point entry completion design. Since mid-2025, we've made several minor modifications that have had significant impacts, including using finer mesh sand to improve predictability of sand placement, increasing maximum operating pressure through a simple frac sleeve design change, which enables higher pump rates in the tows and refining and standardizing dual frac operations. Through these and other optimizations, we've driven an average 12% improvement in sand placed per day. We've also recently broke the prior operator record of 64 stages per day reaching 81 stages and 3,650 tonnes in a single day, resulting in a pad average of over 2,500 tonnes per day.

We expect to carry the same performance into '26. And finally, the chart on the right shows our Duvernay completion performance. This has been a legacy plug and perf across all operators. So the key has been applying our internal workflows to the design, the execution and real-time frac optimization. These are the same processes we've been refining at Musreau. As a result, we've achieved an average 12% improvement in efficiency relative to '24. The most -- one of the most impactful design changes that we've made is running larger diameter casing in the lateral, which enables higher pump rates at the same operating pressure. And if you look back, specifically at the wells where we've implemented this latest design change, we're seeing a 33% increase in completion efficiency compared to the prior design. And we expect those gains will continue into this year.

Next slide is commentary on production and frac optimization. We will highlight some of the work we've done to ensure we're getting the most out of every dollar of capital we spend, really taking that optimization to the next step. While capital efficiency is critical, completions are way more than just simply pumping as much sand as possible on a day. We also need to drive frac effectiveness, which we define as a percentage of the lateral that is effectively stimulated. That effectiveness is enabled through our execution workflows, supported by a group of technical professionals and 24/7 manned frac rooms, aided by advanced real-time diagnostics, automation and continuous monitoring.

The results are shown in the graph on the left -- the graphic on the left. What you're seeing here are 2 side-by-side pads in the Kaybob Duvernay. Red indicates poorly stimulated zones and green indicates properly stimulated zones. The pad on the left was completed by a previous operator using a cookie-cutter design with minimal diagnostics and limited optimization. The pad on the right was completed by Whitecap using a tailored design and real-time monitoring to ensure consistent and proper stimulation across the lateral. The result was a 14% improvement in completion effectiveness, which is consistent with what we have observed across many of the other offset pads we've analyzed. Importantly, the same workflows are applied across all Whitecap plug-and-perf operations.

The last point I'll make here on this slide relates to our team of Calgary and field-based personnel focused on base production optimization, nothing fancy, just strong production engineering combined with 24/7 surveillance.

Base optimization is critical. In the second half of 2025 alone, we delivered an improvement of approximately 4,000 BOE per day on base wells in the Gold Creek and Karr assets versus the previous established trends. These gains are coming from efforts across several fronts, including predicting and optimizing artificial lift, minimizing downtime, facility debottlenecks and pipeline pressure reduction projects.

The example shown on the right reflects exactly that approach. This is a 10-well pad that began producing in 2022, ahead of extensive drilling campaigns by prior operators. As development progressed and attention shifted to the new wells, this pad is left producing into higher line pressures, which drove higher downtime and lower production. Through a focused initiative to reduce this line pressure enabled by compression expansion and optimization, we shifted performance to the green line shown here, delivering a meaningful uplift to the compared prior trend. And this is really where our rigor, workflow and culture come together. It's a major contributor to the confidence we have in our forward guidance. .

And with that, I will now pass it off to Chris Bullin, Vice President of our Conventional division to speak to that asset base.

Thanks, Travis, and good morning, everyone. Our conventional assets produce about 140,000 BOE per day with roughly 80% oil and NGLs. That production comes from a diversified footprint stretching from the Peace River Arch in Northwestern Alberta through Central Alberta and across Southwestern and Southeastern Saskatchewan. Over the past 16 years, we've grown this business substantially. And that growth hasn't been by chance. It reflects our ability to identify opportunities, execute and continuously elevate the organization through strategy, technical depth and operational excellence. When you take a step back and look at the map, it's clear how significant this division has become. We're the second largest light oil producer in Canada and the largest in Saskatchewan. Today, we have more than 3 million acres across multiple high-return play types, all actively competing for capital within the Whitecap portfolio and a multi-decade inventory of 5,800 locations, supported by 52,000 barrels per day of dedicated low decline waterflood and EOR assets. As we discussed earlier, the majority of our conventional assets sit in the stabilizing category.

And in the next slides, we'll expand on the resource potential and longevity of this division, particularly the upside in secondary recovery and EOR. These are not legacy properties. They are strategic to our long-term vision. They provide a stable, predictable low-decline foundation with strong cash flows, deep inventory, technical understanding, our proven track record and operational resilience. And because we operate with an established infrastructure and facility networks, we capture full cycle cost advantages and reduce capital risk. Together, our conventional and unconventional divisions form a balanced, high-margin, long-life portfolio, and that balance is a key competitive advantage for Whitecap.

We'll now turn to our conventional inventory and highlight 2 key takeaways. First, we are inventory-rich with approximately 5,800 locations. Now that represents a multi-decade runway of both premium locations and future upside, especially when you consider our 2026 program is just over 150 wells. Importantly, this inventory doesn't stay static. This year, our teams upgraded roughly 400 premium locations increasing premium inventory from 2,600 to 2,900 locations even after accounting for wells drilled. So that's a great example of how ongoing technical work continues to extend our runway and improve the quality of our inventory. And with only 40% of our conventional inventory currently booked as proved and probable reserves, we retain a long runway to continue enhancing locations and benefit from future technical advancements while also reflecting a disciplined and conservative booking strategy.

The second key takeaway is that our conventional inventory remains highly competitive within the broader Whitecap portfolio. Our conventional assets are benefiting from more balanced and deliberate capital programs across our multiple regions, which has driven better capital efficiency and improved returns on capital. This approach has also strengthened our partnerships with service providers, enabling longer-term commitments and consistent access to top-tier equipment and crews. .

The takeaway from this slide and the next is simple. Whitecap has a dominant position in large, scalable, long-life conventional assets, and we believe they can generate meaningful investor returns for decades. On this map, you can see the scale of our key conventional resource areas. These are large, high-quality reservoirs where a meaningful portion of the original oil in place has already been converted into long life, low decline stabilizing production. Across our EOR focused assets alone, our internal estimates indicate approximately 14 billion barrels of gross original oil in place supported by an aggregate forecast recovery factor of 35% over time.

And importantly, there is still significant resource left to capture, even when we focus only on projects already utilizing secondary and tertiary recovery. Those projects carry a 2P NPV of approximately $8 billion at year-end 2024. Another advantage is that many of these projects already have some infrastructure and capital in place, which improves the economics and reduces the risk of future expansions. Ultimately, recoveries to date prove the resources there. The development model works and our team has a proven track record of extracting value from these assets. For us, large OOIP means these assets are nowhere near being tapped out. In fact, we just scratched the surface on some. Every incremental improvement in expanding already established and proven waterfloods or tertiary floods translates into step changes in recovery factors because the underlying asset base is so substantial. That's the advantage of size, scale and experience in large OOIP reservoirs as small gains and recovery factors become millions of barrels of additional reserves and decades of optionality. For context, 52,000 barrels per day of EOR production is only 19 million barrels per year. So while the risk recovery remains of 700 million barrels may seem small relative to the others in that table, it represents over 35 years of recoveries at 52,000 barrels per day.

Now this isn't blue sky potential as these opportunities are grounded in what we've already delivered from the projects that are already utilizing secondary and tertiary recovery and the repeatability of results across a very large and predictable set of resources is substantial. To highlight these future upside opportunities, we'll start at the top and we'll work our way down the list. First, Alberta Conventional. The future potential here comes from a variety of projects. The Cardium has demonstrated improved recovery and lower declines already in established waterfloods, giving confidence that further expansion can extend asset life. Secondly, EOR upside has been identified in Boundary Lake, which is a very mature waterflood with large OOIP and infrastructure in place, would provide for increased recoveries through polymer implementation.

Lastly, gas injection is being assessed on a variety of horizons, including Boundary Lake, Cardium and also in the Glauconite. Southwest Saskatchewan is the area with the most production from waterflood assets at 19,000 barrels per day and the most recoveries at 900 million barrels to date. We already have active polymer floods and further upside would be seen with waterflood expansion, additional polymer implementation and lastly, gas flooding is also currently being scoped by the teams. Eastern Saskatchewan, where we were focused on the Bakken, provides a clear example. Today, only 1/3 of our active development is under waterflood and only about 25% of our forecasted OOIP has been recovered to date. Our team has a line of sight to a significant waterflood expansion over time into areas that are currently on primary recovery only, and further technological advancements have the potential to unlock significant value in our large Bakken land base. Accordingly, our teams are also advancing scoping level assessments across a range of gas scenarios, including CO2 and ethane to evaluate technical feasibility and capital requirements.

And last but not least, Weyburn, where we recently began CO2 injection into the Frobisher zone, which lies beneath the existing Weyburn and Midale unit. CO2 injection commenced in late 2023, and we continue to evaluate the results from our initial pilot, we'll focus on understanding commerciality, scalability and how this opportunity may fit within our longer-term EOR development plans. Importantly, this pilot leverages existing CO2 infrastructure, making it a strong brownfield example that allowed us to move efficiently while gathering valuable technical and economic data. That combination of high confidence today plus multi-decade recovery upside for tomorrow is exactly what differentiates these assets and anchors long-term shareholder value.

One of the best examples of how we continue to optimize large OOIP assets and a global benchmark for secondary and tertiary recovery is the Weyburn CO2 EOR project. Weyburn has over 70 years of continuous production and represents one of the longest and most data-rich CO2 EOR track records in the world. To date, the field has produced approximately 600 million barrels of oil. And since CO2 injection began in 2000, it has also safely stored over 41 million tonnes of third-party CO2. As you can see on the production profile, this operating history gives us exceptional confidence in recovery factors, decline behavior and capital durability. Weyburn has proven, and it clearly demonstrates that tertiary recovery can reliably convert large volumes of OOIP into long-life predictable production. Importantly, Weyburn also provides decades of learnings around pattern design, CO2 utilization, sweep efficiency and conformance control, which helps us to materially derisk the application of EOR across other suitable reservoirs in our portfolio. .

That gives Whitecap a real technical advantage. We can deploy capital to EOR projects selectively and prudently rather than committing risk capital to unproven recovery concepts. And our understanding of this asset continues to evolve. Recent geo modeling and internal reservoir simulations increased our estimated gross OOIP by approximately 20% to about 1.8 billion barrels. We've also expanded our projected recoveries into adjacent lands outside the unit and the underlying Frobisher zone, bringing total gross OOIP to approximately 2.5 billion barrels. So the key takeaway here is confidence and asset duration. Weyburn is the benchmark that proves low-risk recovery upside remains, and it reinforces the multi-decade EOR potential across our broader portfolio.

Lastly, on the EOR theme, we wanted to highlight the economics of EOR using a typical Weyburn rollout as an example. A full rollout typically consisting of horizontal producer injector pairs can take over a year to fully deploy. Now because these projects are longer cycle, they don't optimize for the fastest payout the way short-cycle drilling does. Instead, they optimize for value, enhancing net present value and profit to investment ratios. And because they deliver low decline, high netback barrels, they provide long-term predictable production profiles that help stabilize the business through commodity cycles. You can see in the cumulative production curve, EOR projects start more gradually, but they build momentum over time with production often peaking more than 5 years after the initial investment. And to put that in perspective, a typical Weyburn rollout generates roughly 7x its invested capital over its life cycle, shifting the conversation from speed of payout to magnitude of payout.

On the final 2 slides on the conventional division, we'll highlight how improvements in well design and execution across our portfolio are driving better capital efficiencies and higher profitability. Starting in the Bakken. This slide shows the evolution of our open-hole multilateral development, moving from a 1-mile design to 2-mile multilaterals and now to 3-mile multilaterals. The key takeaway is that we've systematically increased reservoir contact through longer laterals and the results are clear. Compared to our 2022 program, which includes 3 wells averaging 1 mile laterals, our 2025 program to date includes 6 wells averaging just over 2 miles. We're maximizing reservoir contact and productive capability without sacrificing capital efficiency. We're still in the early stages of open-hole multilateral development in the Bakken and we're excited about the runway to continue advancing performance.

Moving to the Cardium. Recent success has been driven by an optimized completion design using workflows and learnings from our unconventional assets. Following a detailed review of our 2025 program of 11 wells, we identified an opportunity to improve performance through tighter cluster spacing and higher proppant intensity. Compared to the year's prior legacy design, this year's program delivered a 30% improvement on an IP180 basis and improved capital efficiency by 11%. And in the Frobisher, our continued focus is on maximizing reservoir contact through both longer laterals and additional lateral legs. Relative to 2022, our average leg count per well has increased from roughly 2 to 2.6 in 2025. And that's a 30% increase in reservoir contact. That design evolution has driven a 30% improvement in 6-month cumulative oil recoveries translating into a 30% uplift in NPV. These are just a few examples of how we continue to improve asset duration and returns across the conventional portfolio.

And with that, I'll pass it to Travis to walk through the conventional drilling performance.

Thanks, Chris. On this slide, I'll quickly highlight some of the gains we made in drilling efficiency across some of our more active conventional assets. Drilling in these areas isn't overly complex. It's just consistent application of good drilling practices and a hyper focus on reducing downtime and eliminating nonproductive time. The slide on the left shows ROP in our Frobisher play where we have recently seen an 8% improvement. The key here is to maximize ROP with staying in zone, a balancing act that our geology and drilling teams handle very well. We have also continued to focus on reducing sidetrack times and increasing on-bottom drilling ROP through various advancements to bit design. The middle chart shows our Bakken open hole multi-lats where we have achieved a 14% improvement to overall ROP. This has been done through eliminating nonproductive drilling practices as well as improved directional profiles to reduce torque and drag leading to less slide time. Importantly, we've also worked diligently with our directional provider to reduce failures and to push our BHA life to over 250 hours, whereas the area norm would be closer to 100 hours.

Lastly, the chart on the right shows our legacy Central Alberta Glauconite drilling where we continue to implement our monobore design that previously reduced costs by 10%. Of note, in Q4 2025, we drilled the pacesetter 2-well pad with average ROP of around 355 meters per day, compared to the area average of less than 250 meters per day. And as we move into '26, we will continue to apply the same philosophy of continuous improvement to seek out further drilling and completion efficiency gains across our entire asset base. With that, I'll now pass it back to Grant to finish off the presentation.

Thanks, Travis. Chris, Joey and Thanh for walking us through the business components and the work that our teams are doing across our portfolio. To close out, I'll spend a few next few slides, bringing it together everything we've covered in the balance of the presentation and what it means for Whitecap going forward. To wrap up, we've outlined the multiple pathways we have in front of us to continue advancing the business and delivering increased shareholder returns for decades to come. Our starting point in 2026 guidance of 370,000 to 375,000 BOE per day delivered across a diversified set of play types and commodities that includes light oil, liquids-rich natural gas and high deliverable natural gas inventory. In the near term, we also have approximately 90,000 BOE per day of available infrastructure capacity that can be utilized for quick production additions if required. That capacity comes from debottlenecking and further utilization of existing infrastructure as well as our LATOR Phase 1, which is approximately 50% complete as of today. Beyond that, we've also outlined a series of project level growth that in aggregate, represent approximately 325,000 BOE per day of organic growth potential. These include LATOR Phase 2, Gold Creek and Karr expansions, Resthaven lean gas development, Kakwa expansion. And finally, we've highlighted why our conventional portfolio is a key differentiator for Whitecap.

We continue to advance new and improving technologies in open hole multilaterals as well as drilling longer laterals with monobores, driving costs down while improving recoveries and asset profitability. In many respects, we're still in the early innings of unlocking its full potential. The fact that an asset like Weyburn with more than 70 years of production history continues to offer meaningful runway and reinforces the durability and long life value embedded across our portfolio. The takeaway is simple. Our asset base is large in both order of magnitude and long-term profitability, and our focus remains maximizing returns and profitability in any commodity price environment. Our diversified long-dated inventory provides significant strategic flexibility, but also means there are many multiple pathways we can take to advance the business.

On this slide, slide on growth optionality, we provided illustrative outcomes aligned with our corporate strategy of 3% to 5% production per share growth annually while including a stay flat scenario, that we employ in a low commodity price environment. These outcomes reflect our capital allocation strategy. In moderate commodity price environment, we would introduce growth while still prioritizing the balance sheet and share repurchases. As commodity prices move higher, we would allocate more capital towards organic growth where returns on our invested capital improve both near-term results and the free cash flow generated as prices normalize and growth moderates again. In these scenarios, annual capital would range from approximately $2 billion to $2.8 billion, fluctuating based on the pace of growth and which projects are deployed under different commodity price environments. Ultimately, we'd hope the takeaway from this slide and from the presentation as a whole is that we have an ability to adjust both pace and asset mix across our broad range of outcomes, not only over the next 5 years, but for a significant period of time beyond that.

To close on Slide 45, build to provide durable returns. We'll circle back to the advantages that underpin our strategy and our ability to deliver long-term shareholder value through commodity price cycles. Our strategy is built on 4 core pillars: high-quality inventory, the significant depth, technical excellence and top-tier operating performance, capital discipline and a strong balance sheet. Our intention is to leverage the strength of all 4 pillars to drive free funds flow and deliver superior shareholder returns now and for decades to come. Before we conclude, I would like to recognize our staff both in the field and in the office for their dedication and continuous pursuit of improving profitability of this company. I also want to thank our Board of Directors for their guidance and their support. With that, I will now turn the call back to the operator, Sylvie, for any questions. Thanks very much.

[Operator Instructions] First, we will hear from Dennis Fong at CIBC World Market.

My first one is focused on just aggregate strategy. You mentioned very briefly in it in terms of how you think about your current depth of inventory. You obviously have a lot between both the conventional and unconventional. Obviously, in a volatile commodity price environment with the strength of your balance sheet, how do you think about being opportunistic in the specific situation? Obviously, understanding that internally, your portfolio is quite robust.

Yes. So thanks, Dennis. Just on the acquisition side, I mean I think that's what you're leaning towards. I mean what we look at, firstly, as we've tried to imply through the presentation, is that the -- we'll continue to -- with each one of our teams and our business development team, we'll look at opportunities into the future. The key component for us is when we talk about counter cyclicality is making sure that we have the strong balance sheet in order to do that. So at this particular time, relative to acquisitions, that isn't our primary driver because we have enough inventory to grow organically at this particular time, and we'll always have that. But if we can supplement that through acquisitions into the future, our balance sheet, we feel that's appropriate with our balance sheet strength, we'll look to do it. But at this particular time, our primary focus is going to be on organic growth as we advance forward or organic spending as we advance forward. .

Appreciate that context and that background there. When we think about my next one kind of shifts towards the organic growth portfolio. So when we think about that 325,000 BOEs a day of incremental growth projects beyond LATOR Phase 1, what stages of engineering are some of those projects in currently? And then what kind of either commodity price environment or key kind of technical milestones are you guys looking forward for to feel more comfortable about sanctioning or moving forward with those projects?

Dennis, Joey Wong here. Thanks for the question there on the projects. And maybe I'll talk about the projects and the underlying inventory kind of in conjunction because they kind of relate. So the projects themselves, they're in various stages of either understanding of the facility that's going to be needed for it or of understanding what we intend to do in order to fill it in the first place. So to give an example of that, that something could be a little bit further progress would be the one we spoke to in Gold Creek, that's an expansion of an existing facility. So the 25,000 barrel a day add that we have there is actually it's a bolt-on. So that will be relatively far down the line. There's actually even to the point where there's space on the lease for us. So that one is relatively far progressed. And then on the other end of the spectrum would be like we had mentioned there, Resthaven, where like I say, we do have a very, very solid understanding of the asset in terms of what it would be without things like the 2 dozen wells that we have and all of the work that we've done from a subservice point of view, but it isn't to the point that we have the understanding on something like Gold Creek.

So it all exists on the spectrum, Dennis. Our intent as we go through our capital programs, though, is to introduce sleeves of activity that would be strategic in nature to progress some of those things. And like I mentioned there in the prepared remarks, the 2 wells that we have in Resthaven, we'll start to further that. We'll take the legacy data that we have, make sure it matches up with the translation into modern results and then we start to build from that. To come to your question there on how we would progress a sanctioning of a project, these are big things when we start to look at these larger legs of growth. And we would do those with a view to the long-term pricing that we see and ensuring that what we are left with in the overall portfolio gives us the same optionality that we enjoy today.

So one of the key derisking mechanisms that we have in our corporate growth profile is -- like we outlined at fair detail here, the flexibility that we have or the optionality that we have to allocate capital throughout different price cycles, we want to make sure we retain that. So if we find ourselves at a place where -- let's just use a theoretical case where we fill up the majority of our liquids-rich gassy capacity, but we're long on the condensate side. Well, we would probably look to supplement the liquids-rich side, so we maintain that flexibility as long as the long-term commodity prices are supportive of that. So again, it's a lot of words there to describe the fact that we like what we have today, and we want to continue to build that out to maintain that optionality in the future.

I'm just going to read out the next question here that we have from Aaron Bilkoski with TD Cowen. With oil strip below $60 and reasonably strong North American gas prices, at the margin, do you see Whitecap allocating some capital to more gassier windows of the Montney than you would have if oil was $65 plus.

Our comment to that really is when you look at the oil price today at $58 and where the Canadian dollar is currently trading at about $0.72, you're still seeing Canadian WTI prices in excess of $80 compared to AECO pricing for the balance of the year in 2026, somewhere in that $2.80 there. So when we look at the economic profile of oil and condensate opportunities as well as liquids-rich opportunities, they still provide better returns than the more gassier opportunities. So we think the development program that we've outlined for 2026 is very balanced and really optimizes the return profile at this time.

Okay. The next question is, where are your light oil barrels destined? And is there sufficient capacity in pipeline?

And so from our perspective, a lot of our light oil is centered in Saskatchewan, which is closer to the border between U.S. and Canada. And so we've been able to move our product very easily through -- on the light oil side there. So we haven't had any issues being able to produce and sell our product there. In terms of the condensate there, it's obviously being used as a dilutant in the oil sands there. So there's a natural ability for us to sell that domestically. The light oil goes to Edmonton pad 2 and to Eastern Canada there. So no issues from an egress perspective.

[Operator Instructions] Next, you will hear from Phillips Johnston at Capital One Securities.

I wanted to ask about what your next 12-month corporate PDP decline rate looks like today. And maybe within that company-wide average, what does the decline rate look like for both your conventional production as well as your unconventional production?

Yes. Thanks very much for your question. From an overall corporate perspective, our decline rate is between 28% to 29%. At this particular time, broken down, we're 19% to 20% on our conventional assets today, and our unconventional assets are declining between anywhere between 32% to 33% at this particular time.

Okay. Great. And then your capital budget this year, $2 billion to $2.1 billion, that is expected to generate some production growth. Within that figure, what would you estimate is your maintenance CapEx that would be required to just keep current production volumes flat?

Yes. So the maintenance CapEx there would be somewhere between $1.9 billion to $2 billion to keep production flat.

Thank you. And at this time, we have no other questions registered on the floor. Please proceed.

So the next question we have from [ Darren Stephens ], what is the AECO natural gas price today and what gas price do you see reasonable for 2026 and 2027 forecast?

Well, the price today is natural gas prices on the Canadian side. AECO prices are about $2.80 per GJ. And for the average for 2026, the prices are approximately $2.60 at this particular time. So we're forecasting $3 as an average for the year at this particular time, we'll make adjustments if we see necessary. And for 2027, we think that ultimately, the gas prices do come back once we have incremental takeaway capacity or we fulfill the obligations to LNG Canada 1 and 2 into 2027. So we feel longer term gas prices will stabilize somewhere in that neighborhood of between CAD 2.75 per GJ to anywhere between up to CAD 3.75 per AECO in 2027, maybe up over $4. But at this particular time, we're using an average price of $3. And why it's particularly important is the takeaway capacity out of Canada is going to be very important as we advance forward. So we'll watch that very closely moving forward.

So the next question is, what would it take to drive all of Whitecap's free cash flow through the buyback given current valuation and soak up the full 10% of our NCIB there.

And so when we look at the oil pricing environment today and we're using $60 WTI, we generate $1.2 billion of free cash flow and $900 million of that is allocated towards our dividend and $300 million towards our share buyback program there, which is about 3% of our float. So I think given where our intrinsic value is and where the share price is, any excess above that will certainly go towards buying back our shares. So that would be our objective at this time here.

I can read out the next one here, from Christian at Peters & Co. So the question says, on the operational improvements you highlighted related to unconventional and conventional business units, how much is factored into formal 2026 guidance. You also touched on some of the improvement initiatives you're targeting in 2026 to further the operational momentum realized over the past 2 years.

So yes, Christian, where we have confidence and we're comfortable underwriting those efficiency gains, we've incorporated those into the program. So maybe I'll take a step back and give an example. Last year things that wouldn't have been incorporated when we started things like piloting the Winerack design took a bit of time to make sure that, that was going to be repeatable before we bake it into the program. But with that said, I can say that the ones that we've seen there, whether that's the outperformance on the production in places like Musreau, Kaybob, the outperformance in the drilling and completions, we've started to build all of those things in, where it's reasonable, recognizing that we are well on our way up the curve there. On the conventional side, any further comments there, Chris?

Yes, to add to that, Joey, I would say, a continued focus really on open-hole multi laterals if we shift to the Bakken in Eastern Saskatchewan. I mean the teams have definitely done a great job there to advance those initiatives as we've shown on the design optimization slide. And not just in some of the areas that we're starting to push play edges, but also from the conversion of more of the historical multi-stage frac technology, looking to convert to open hole multilaterals where we can. So the teams are stepping through that process very methodically right now to better understand that upside potential.

Another key focus area for additional optimization potential for us, again, it remains to be the Frobisher and once again, the teams have done a great job there showing that progression over time, focusing on additional lateral lengths where we can. And really just at the end of the day, just trying to maximize our total development costs at the end of the day. So we want to be as efficient as possible. And other thing to note, too, is that we're in such a strong position that we don't need to take any unnecessary risks within our portfolio, too. So everything is a very measured approach when we go through that very systematically from kind of decision analysis perspective, so definitely a competitive advantage for us in that regard, too.

The next question is, do you have access to natural gas markets that aren't constrained by AECO pricing?

So currently, our mix there is we've got 78% exposed to AECO of which 29% of that production has been hedged for 2026 at $3.76 per GJ and 22% is exposed to other markets, including Dawn, the U.S. Midwest and Henry Hub. And we've seen the importance of price diversification. If you look at our Q3 report, where we realized almost double the price of AECO as a result of that. So longer term, there is certainly a target to continue to move some of that exposure away from AECO because we do think that is important in terms of the pricing mix.

Just really quickly on another question we have. What do you expect Whitecap's production mix, crude oil, natural gas, NGLs to be in 2026.

As we talked about in the presentation, we expect this year to be 60% oil and liquids and 40% natural gas.

Do you have other questions?

At this time, there are no questions on the phone.

Thank you, Sylvie. Once again, we appreciate you taking the time and interest to listen today. We are excited to continue down the path and generate significant value for shareholders now and for many years to come. Lastly, I would again like to emphasize it's with the appreciation of the hard work of our staff within the office and field that we're able to pull all of this. Not only it's information together, but the operational excellence that we've been able to demonstrate. I want to thank you for your performance and look forward to an exciting 2026. Thanks very much, everyone.

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

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 Q3 2025 Results and 2026 Budget Conference Call. [Operator Instructions] And I would like to turn the conference over to Whitecap's President and CEO, Mr. Grant Fagerheim. Please go ahead.

Thanks very much, Sylvie, and good morning, everyone, and thank you for joining us. There are 5 members of our management team here with me today, our Senior Vice President and CFO, Thanh Kang; our Senior Vice President, Production and Operations, Joel Armstrong; our Senior Vice President, Business Development, Information Technology; Dave Mombourquette; our Vice President of the Unconventional Division, Joey Wong, and our Vice President, Conventional division, 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 that was issued yesterday afternoon. We are very pleased to provide our shareholders with this update this morning as evidenced by our third quarter operating results and the 2026 released -- budget released yesterday. The first full quarter following the integration of the Veren assets into Whitecap portfolio has been highly successful. The company's assets and personnel are strategically aligned, driving operational efficiency and value creation. Our top-performing assets serve as key differentiators, reinforcing the company's competitive advantage and supporting long-term growth well into the future.

Third quarter production of 37,623 BOE per day which included 227,419 BOE per day of total liquids and 883 million a day of natural gas. Strong operating performance has continued throughout the entire year supported by the seamless integration of the Veren assets and field operating teams, which has enhanced overall operating efficiency. As a result, we are increasing our 2025 guidance to 305,000 BOE per day for the full year, which implies 370,000 BOE per day for the fourth quarter, while our full year capital program of $2 billion remains unchanged. By leveraging the collective knowledge and technical understanding of the combined assets, and operations, our 2026 budget is set to deliver robust free cash flow from a very efficient capital drilling program. Our 2026 budget has been set between $2 billion to $2.1 billion, which is forecast to deliver average production of between 370,000 to 375,000 BOE per day and an exit production rate in excess of 380,000 BOE per day to grow production per share by 3%.

The capital program is down from initial capital projections to that $2.1 billion to -- $2.0 billion to $2.1 billion from what was $2.6 billion. Our Unconventional division will be allocated 75% of the capital budget to drill approximately 100 wells, while the Conventional division will receive the remaining 25% to drill approximately 155 wells. We're particularly excited for our Lator asset where our 04-13 battery is on budget and ahead of schedule. Joey will provide more details on our plans for this asset in 2026. But needless to say, we're looking forward to development of this liquids-rich asset base in the near future.

The capital efficiency embedded in our budget is approximately 10% better than the previous forecast, which can be attributed to recent operational performance, asset allocation and the realization of synergies. In aggregate, we have included $300 million in forecasted synergies for 2026 or 40% higher than our original estimate of $210 million. Capital synergies of approximately $130 million were driven by enhanced procurement, operational efficiencies and rig line optimization. Operating cost synergies equate to $135 million which is $60 million higher than our original estimate. We are seeing significant wins in areas with adjacent or overlapping operations along with procurement success and operational best practices.

Lastly, we have realized $35 million of corporate synergies through reductions in G&A, share-based compensation and interest expense. These benefits are a direct result of the combination, leveraging enhanced scale, integration and the technical best practices that were previously divided between the 2 organizations. I want to thank our entire office and field teams for their technical rigor and dedication in achieving a significantly higher synergy realization and doing so much faster than initially anticipated. Our culture of continuous improvement positions us to further enhance these synergies through ongoing technical initiatives planned for 2026. I will now pass the mic on to Thanh Kang to further discuss our third quarter financial results and provide more details to our 2026 budget. Thank you.

Thanks, Grant. U.S. dollar WTI remained relatively stable at $65 per barrel in Q3 compared to $64 per barrel in Q2, in contrast to a weaker AECO price of $0.63 per Mcf. Whitecap was, however, able to achieve a significantly higher price realization of $1.31 per Mcf due to our price diversification efforts. Although natural gas accounted for 39% of our production, it only represented 6% of our revenues in the third quarter. From an upside perspective, a dollar change to AECO would increase our free funds flow by $200 million. Operating costs in the quarter decreased by 8% to $12.50 per BOE compared to the second quarter due to early synergy realizations. Current income tax was $25 million in the quarter represents a low pretax funds flow rate of 4%. Tax pools at the end of the quarter were $9.8 billion, of which $4.4 billion were noncapital losses providing us with strong tax coverage for 2026. Our light oil and condensate weighted portfolio, combined with a lower cost structure, generated funds flow of nearly $900 million in the third quarter and after capital expenditures of approximately $550 million, free funds flow was $350 million.

Returns to shareholders in the third quarter were approximately $400 million as $221 million of base dividends were enhanced by approximately $180 million in share repurchases under our NCIB reducing our share count by almost 2%. The company's balance sheet remains strong with net debt of $3.3 billion at the end of the quarter, including $1.7 billion in investment-grade senior notes. Supported by this solid financial foundation and our prudent hedge positions for 2026, we are well positioned to manage commodity price volatility and maintain long-term financial stability. For 2026, based on $60 WTI and $3 AECO we anticipate funds flow of $3.3 billion. And after capital investments of $2.1 billion we generate free fund flow of $1.2 billion. This allows us to return $900 million in dividends to shareholders and the opportunity to repurchase $300 million worth of shares to reduce our share count by a further 2% enhancing our per share metrics.

Our commodity price sensitivity for 2026 are as follows: for every dollar U.S. change in WTI, our funds flow increases by $50 million. For every $0.10 per GJ change in AECO, our funds flow increases by $20 million and for every penny change in the USD FX rate, our funds flow is impacted by $45 million. I'll now pass it off to Joey for more remarks on our Unconventional third quarter results and 2026 budget.

Thanks Thanh. Our Unconventional portfolio continued to deliver impressive results during the third quarter with asset level performance exceeding internal forecasts. These performance benefited from optimization efforts in the quarter, while capital efficiencies and cycle times on new drills continued to exceed expectations. Following the successful integration of Veren's assets and teams we shifted our focus to optimizing our expanded asset base during the third quarter. A key part of that optimization has been applying our unconventional workflow to tailor development in each area to the underlying geological and reservoir characteristics and to refine those designs in real time throughout the various phases of execution. This workflow, which leverages technical best practices to enhance repeatability and economic returns has already yielded significant capital and operational efficiency improvements across the portfolio. Initial optimization efforts have driven measurable efficiency gains in our Montney and Duvernay drilling and completions programs, shortening cycle times and improving key performance indicators.

At Kaybob, meters per day drilling performance improved by roughly 20% year-over-year, including a new pacesetter pad drilled at approximately 600 meters per day. Real-time frac monitoring and optimization of completions practices also contributed to an 8% reduction in average completion times across the Duvernay. At Musreau, we achieved a 20% decrease in drilling costs from an improvement in drilling performance on our most recent 6-well Montney pad compared to our first 16 wells in the play. Collectively, these results highlight the strength of our integrated in-house capabilities, bringing together geoscience, engineering and operations to capture design efficiencies and enhance execution across development programs. This collaboration supported by our extensive proprietary data set allows for continuous improvement and the effective transfer of best practices throughout the unconventional portfolio.

At Gold Creek and Karr, initial enhancement initiatives focused on improving base production through the optimization of artificial lift, gathering systems and other best practices along with targeted infrastructure improvements, such as mitigating measures for high or low ambient temperatures. Across our operated asset base, we place a high priority on anticipating changes in production requirements through different phases of field life. This is particularly important as we introduce new volumes from our capital programs where protecting base production remains a core focus. These optimization efforts have delivered measurable uplift in productivity on base wells, driving Montney volumes roughly 4,000 BOEs a day above our internal forecast in the third quarter.

Our 2026 capital program will continue to build on this operating momentum as we plan to run a steady seven rig program to drill approximately 100 wells across our Montney and Duvernay assets with 129 wells expected to be brought on production during the year. This program is expected to drive 8% to 10% growth from our unconventional assets as measured from exit to exit. At Kaybob, we plan to spud 45 Duvernay wells across a 3-rig program in 2026, utilizing a wine rack design on approximately half of the planned pads. Development will be focused within our core areas to maximize the utilization of expanded infrastructure capacity and enhance overall asset profitability.

We plan to spend approximately $55 million to modestly expand, debottleneck and connect existing infrastructure in 2026, following up on the success of our expansion efforts at our 15-07 gas processing facility in 2025. These infrastructure optimization projects will support growth in the play over the near term with total capacity in the Kaybob region increasing to 115,000 BOEs per day to 120,000 BOEs per day and by the second half of 2026. We expect to fully utilize our expanded capacity in the second half of 2027.

Moving over to the Montney, we plan to spud 53 wells in 2026 across a 4-rig program and bring 74 operated wells on production from our 2025 and 2026 programs. In Gold Creek and Karr, we plan to spud 29 wells and bringing 48 wells on production in 2026 with development focused on well-understood areas with existing infrastructure capacity. Following a detailed technical review of subsurface data in addition to recent and legacy well results in the play, we commenced drilling operations on our first of 2 plug and perf pilot pads in the Karr area in the fourth quarter of 2025. This 4-well pad will be followed by a 3-well pad, which has been strategically selected to test the application of this completion design with defined control parameters to evaluate performance. If designed and executed properly, plug and perf completions are expected to lower cost by $1 million to $1.5 million per well relative to a single point entry design.

Early results of this pilot activity in Karr are expected to be available in the first half of 2026. With success, we also plan to drill a plug and perf pilot pad in Gold Creek in the second half of 2026 with the same level of control parameters as the Karr pilots. While meaningful in its potential impact, our rollout of this technology will remain measured representing roughly 1/4 of the total wells being brought on production in 2026 in Gold Creek and Karr. This reflects our deliberate step-wise approach to improving capital efficiencies and fully recognizes and limits the potential risk to asset level performance, while pad design and execution are fine-tuned. Results from these pilot pads will inform future well designs as we seek to derisk development and maximize long-term value of the assets.

At Musreau, we plan to drill 11 Montney wells on the eastern portion of our acreage in 2026 as we continue to leverage multi-bench development and manage drawdown to optimize per well recoveries. We will also allocate approximately $5 million to enhance gas lift capabilities at our 05-09 facility in the second half of 2026, supporting further optimization of the strong condensate volumes being realized from this asset which have exceeded expectations due to our development and production practices. We plan to spud a 2-well delineation pad at Resthaven in 2026, which is a Southeastern extension of our Lator Montney land base. The pad is expected to come on stream in the second half of the year. Results from this pad will provide us with important technical information as we evaluate the economic viability of this sizable and prolific natural gas weighted acreage.

Lastly, our Lator Montney asset will move towards development mode in 2026. Following a successful engineering and design and permitting process construction on the 04-13 Lator facility has been progressing ahead of schedule and within budgeted capital expectations. This has allowed us to advance expected commissioning and start-up to the fourth quarter of 2026 from our initial target of late 2026 to early 2027. Continued technical work and strong well results are reaffirming our expectations in the deliverability and long-term development potential of this area. We plan to drill 11 wells in the area and spend approximately $180 million of capital in 2026, including $60 million on supporting infrastructure projects such as water disposal and gathering lines to support the ramp-up of the 04-13 facility. Production is expected to ramp towards the design facility capacity of 35,000 to 40,000 BOEs per day throughout 2027 at a measured pace allowing for continued optimization of development plans where warranted.

With that, I will now pass it over to Chris Bullin to talk about our conventional assets.

Thanks, Joey. Our conventional division delivered another strong quarter benefiting from consistent operational execution across our Alberta and Saskatchewan assets, along with efficiency improvements following the successful integration of our expanded portfolio. In 2026, we plan to drill 156 wells across our conventional division, focusing on plays with short cycle times, quick payouts and high netbacks. This activity is expected to maintain conventional production in the range of 135,000 to 140,000 BOE per day while generating $900 million of asset-level free cash flow highlighting the outsized profitability of our conventional assets and the underlying strength of our diversified and complementary portfolio.

Our 2026 capital program is structured to maximize optionality providing flexibility to adjust capital allocation and activity levels in response to changes in commodity prices. Our teams will continue to maintain a state of readiness, ensuring we can act quickly as market conditions evolve. This disciplined approach ensures we can protect free cash flow, sustain returns and capture upside when market fundamentals improve. We will continue to look for opportunities to incorporate shared learnings from our unconventional workflow within our conventional assets in 2026, including optimizations to our well design and targeted technical enhancements. These initiatives are expected to drive further efficiencies and improve performance across our conventional portfolio.

In East Saskatchewan, we plan to spud 79 wells in 2026, building on the recent success of our Bakken and Frobisher programs. At Viewfield, we will continue to advance our open-hole multilateral program to maximize capital efficiencies and improve the economics of our drilling inventory. Our recently completed 3-mile Bakken pilot well in the area set multiple records within Saskatchewan, including the longest lateral leg drilled to date at over 6,400 meters and the longest total lateral length on a single well at over 34,600 meters. This well was drilled and completed on a dollars per meter basis in line with prior 2-mile open-hole multilateral wells in the area, reinforcing our confidence that lateral lengths exceeding 2 miles can achieve improved capital efficiencies. This supports the inclusion of additional extended lateral length wells into the 2026 program.

Our 2026 Frobisher development will kick off with an active first quarter drilling program with 3 rigs building on strong momentum from 2025 results, which have consistently exceeded expectations. We plan to drill triple leg wells on 15 of 49 planned Frobisher locations, allowing us to increase reservoir contact and maximize the royalty benefits associated with Saskatchewan's multilateral oil well program. Across our Alberta conventional assets, we plan to spud 30 wells in 2026 with activity focused in the Glauconite at Westward Ho and the Cardium formations at Wapiti and Pembina. In the Glauconite, we will use a monobore design on all of our 2026 locations following strong production performance and repeatable cost reductions realized from our 2025 monobore program.

In the Cardium, we will continue to utilize our optimized completion design at Wapiti derived from our unconventional workflow. Our 2026 development in the area will push to the South and the Northwest, expanding from our successful 2025 program. In West Saskatchewan, we have 47 wells planned for next year, targeting the Viking, Atlas and Success formations. Our 2026 program has been level set with a moderation in activity compared to prior years aligning with our strategy to focus on capital discipline, free cash flow generation and sustainability.

Our conventional assets are a strong contributor to our ability to sustain production at lower commodity prices and provides significant torque to increases in crude oil prices. The low 20% decline asset base allows us to shift capital without materially degrading the short and long-term profitability of these assets, and provide the necessary flexibility to enhance the economics of our capital programs.

With that, I will turn it back over to Grant for his closing remarks.

Thanks very much, Thanh, Chris, Joey, for your comments. As we move through the remainder of 2025 and into 2026, as you all know, we are operating from a position of strength. Operationally, performance remains exceptional with faster cycle times across our assets, optimized rig lines and drilling programs, capturing additional efficiencies and the maximization of existing infrastructure to further enhance our profitability. Financially, our 2026 budget is expected to generate substantial free funds flow enabling meaningful returns of capital to shareholders while maintaining balance sheet strength and long-term resiliency. The top-tier asset base we have assembled supported by the long-dated drilling inventory of approximately 11,000 high-quality locations, provides shareholders with decades of profitable and sustainable growth potential. This strong foundation positions us to continue improving capital efficiency and expanding profit margins over time. Furthermore, our technical initiatives planned for 2026 create additional opportunities to outperform our base plan and drive continued value creation.

As we complete our 2025 initiatives, our focus remains on delivering strong shareholder returns in 2026 guided by disciplined execution, operational excellence and prudent financial management. Our total shareholder return target is between 10% to 15% per year and our 2026 budget will deliver on this target through our $0.73 per share dividend annually, which equates to 7% yield at this time, 3% production growth to 380,000 BOE per day and the option to repurchase over 2% of our shares outstanding with excess free funds flow generated at $60 WTI oil. This equates to a 12% total returns to shareholders, which further increases to over 15% at $70 WTI with additional $500 million of free funds flow.

With that, I'll now turn the call over to the operator, Sylvie, for any questions you might have. Thank you.

[Operator Instructions] Our first question comes from Sam Burwell at Jefferies.

I wanted to ask about the 7-rig program across the Montney and Duvernay. Is that fewer rigs than you're running now, fewer rigs than you were originally planning to run in '26. Is this effectively a Veren synergy manifesting itself?

Yes. I guess -- sorry, Joey Wong here to answer the question here for you, Sam. The 7 rigs we're running in 2026, actually match what we're running in the back part of this year in Q4. There have been periods of time in 2025 where we had more running. There's a bit of overlap. And if you recall, some of the discussions we had with respect to the combination was cleaning up a little bit of that where we had fragmented rig lines where you'll have portions of these rig lines stacking up on each other and kind of a concentration of activity at times.

And so I guess answering the last part of your question there Sam, yes, this -- the steady, the reason we used the adjective steady there is definitely one of the synergies that we saw early on when we look at not just the underlying capital efficiencies of just getting things running without, like I say, overlap or gaps. But in addition to that, some of the outperformance we're seeing on the drilling side, we can draw back the consistent use of some of our stronger performing rigs, which the 7 that we have retained are going to fall into that category. And we'll look to then continue to build on those efficiencies through that steady program.

Okay. Got it. And you talked a lot about share repurchases, both in the release and in the opening remarks. So can we expect those to be more ratable over time? Or should those remain something that's deployed in opportunistic situations. Just curious like if you don't see any dislocations, let's say, should we expect most of that free cash flow after the dividend next year to go towards the balance sheet?

Sam, it's Thanh here. So as it relates to the NCIB there, we are targeting the $300 million that we've outlined in the press release there. The way that we're viewing it, Sam, is looking at it from a countercyclical perspective. So generally in a low commodity price environment, what we want to be doing is focusing on maximizing our free cash flow and repurchasing our shares as much as we can here especially when we see quite a bit of a disconnect between where the share price is and where our intrinsic value is. In terms of the execution of it, we're going to be more opportunistic. I would say that number one, when there's large blocks that are available to us, we'll try to clear those with our NCIB or if we're underperforming, then we'll step in and support the stock from that perspective there.

But ultimately, our focus here is to reduce the number of shares that are out, which improves the long-term sustainability of our dividend and it's a permanent improvement to our capital structure. So that's the way that we would look at it. I think that given the volatility here, Sam, what we want to make sure is we're able to realize this free cash flow before we spend it. So we'll continue to monitor that very closely as we walk through 2026.

Next question will be from Patrick O'Rourke at ATB Capital Markets.

So the budget came in at certainly what I think 6 months ago, 1 plus 1 budget of Whitecap and Veren much lower than that would have looked here. And just wondering sort of what the levers you pulled to be able to achieve that is. And then in the updated deck, you talked about free cash flow at a $70 crude price and allocating the incremental free cash flow to share repurchases and debt reduction. I wonder what sort of crude environment and macro conditions Whitecap would need to see out there to sort of have a little bit of a more aggressive capital program going forward?

Yes. Thanks, Patrick. I mean a budget being lower, yes, our capital is lower, but our production, we didn't really lower. So you're right on the capital. And that was a lot of the work that the teams have done, our operating individuals had focused on the synergies that we talked about. We were currently -- we were previously estimating $210 million of synergies, now we're projecting $300 million and potentially more into the future. We're not projecting that at this time. But -- and as we -- I think we talked quite a bit about it through the -- where these improvements came as when we talk about rig lines and all of our best practices and really utilizing the infrastructure more appropriately.

I think that combined with our workflows that we do have within the organization, that's where you're -- where we talk about driving these capital programs down lower.

The operating teams have been busy on our operating group under Joel's guidance have been busy on procurement and understanding what we're going to look like with -- from a capital cost moving forward. But it certainly is dropping capital really more of what we've entered into is more of a defensive style budget for 2026 with a lower commodity price deck with the expectation that, as we know, living in a cyclical commodity price environment, there will be an opportunity to uplift it and we'll be ready to advance capital in the rate environment -- pricing environment.

So as far as specific triggers on, you want to make sure that our leverage stays reasonable, and we're very much measured on that as we advance forward, and it's allowed us to get to this point and we'll continue to have that. So it isn't formulaic, but it will be, you'll look to see us buy back more shares. Trigger for more capital, we'll look at -- we were pretty much set for the first quarter, and we can analyze it after the first quarter period of time as to whether or not we increase capital at that time when commodity prices we'll know further what they're at that time.

Okay. And then maybe a bit more of a technical question here. But in terms of the plug and perf pilots that you're looking at here, I think it's 2 well pads. What are the -- how are you going to benchmark the KPIs in terms of what you would measure success that? And then if it is successful there, if you're able to sort of scale that up from 2 wells to pad scopes that are much larger than that, what would that mean going forward?

Patrick, Joey here. So yes, the first question there on how do we benchmark it, there's quite a few criteria that we look at, both through the execution phase of the completion itself. So as we're watching how efficient the clusters are treating, making sure that the rock is conforming to our designed expectations. And like I mentioned in the prepared notes there, we do have a series of expected criteria through that phase. And what we also have, and this is important is the ability to react. So we have contingency plans if things do start to veer from expected frac behavior, which implies a different frac geometry that we designed, we have the ability to steer that ship.

And that's been one of the things that has been a differentiating factor for us anyways, with respect to the execution of our plug-and-perf programs to date throughout the legacy Whitecap asset base. So that's on the execution side. The benchmarking on the then subsequent on production side will be as we do with really, again, any of our development we look at. Initial on production, we look at how the wells themselves interact between each other and between adjacent wells, which give us indications of what that frac geometry is actually behaving like.

And then what we then do is we look at the long-term trends of, again, those new wells and the existing ones. And it's important to note there that it's -- when we talk about trends, it's not just production. There's downhole pressure. There's temperature and then there's interpreted versions of all of those that go into our systems and we allow ourselves to benchmark through those. So it's a lot of words to describe that. There's quite a bit of eyes on this and quite a bit of criteria that we're going to be looking for in terms of calling that a technical success.

In terms of scale, Patrick, what we've spoken to before is the Karr asset or the Karr portion of the asset base, which would be the kind of the south portion of the legacy Veren assets. There is quite a bit of precedent plug-and-perf application in those lands. And we've looked quite closely at those, gone back and seen what has worked and what hasn't worked. Up in the Gold Creek portion of the asset base, it's -- we'll say, less proven. And we do think that we have a pretty good indication of, again, what was working and what went -- didn't go quite according to plan there with, again, some ability to try to tailor our designs to that.

So ultimately, in a perfect world, you'd start to see these capital efficiency savings throughout the asset base. But like we said there, we probably used the word quite a few times throughout this process. The approach is going to be measured. We feel like 25% of the Gold Creek and Karr activity is appropriate at this stage, given where we're at, and we'll look to march it up from there and avoiding trying to put to firm a target on it. You go from 25% to 50% to 75% over a certain period of time. We try to let the results dictate that instead of putting that target out there.

Next question will be from Dennis Fong at CIBC World Markets.

The first one I want to focus a little bit on the gas lift side. You've optimized part of Gold Creek and Karr really, frankly, driving some volume outperformance and frankly, more to do at Musreau next year. Can you talk towards a little bit of the stage of optimization across the asset base, especially the legacy one. And how should we think about the cadence of working through kind of the upcoming backlog to kind of deploy gas lift in an optimized basis across the entire asset base.

Dennis. So in terms of the gas lift that we've done so far, and I guess I can jump to the second part of your question there with respect to what you're calling a backlog of other stuff. We're largely there, Dennis. Again, it was a lot of the efforts that went in to the infrastructure build-out that was done for that supporting gas lift in both Gold Creek and Karr and then also just the adjustment or I'll call tweaking of the parameters done by the collective field staff to get it done. And that was one of the larger driving factors behind the 4,000 BOE per day beat expectations there internally on the Montney side was really getting all of that done in quite short order, and again, maybe I'll draw back to the comment there about the field teams.

We look at these assets and we say, okay, there probably is -- I'll use your word there, the backlog there is stuff to do, and they did take it upon themselves to hustle through quite a bit of that. And like I said, there's not a lot of low-hanging fruit left. What we now see though, and we built into our forward-looking forecast is the anticipation of getting ahead of this a little bit better. So it's been part of our standard operating practice that we get out and we either adjust gas lift or whatever the artificial lift technology is, adjust those parameters in advance of the need of those things, so that you don't have a sag in production, followed by a restoration of it. We actually get in front of that just to shorten that time. And like I say, that's been built in. And so we'd be -- our intent is to not have a backlog, I guess, is the short way of answering it there, Dennis.

My second question relates to infrastructure spending. It looks like you have a couple of hundred million dollars of that in 2026. Can you talk towards the cadence of, we'll call it, facility build-out and so forth. Obviously, you have the -- that's kind of the near wellbore infrastructure build-out versus the actual facility build-out, which is done by your infrastructure partner. But can you talk towards the cadence of infrastructure spending over the next couple of years because I think capital efficiency becomes that much more impressive if you kind of ex out some of the mid-cycle spending requirements.

Yes, I can speak to that one there again, Dennis. So within the year, I guess, answering the first bit there, within the year, the infrastructure spend that we have planned in both Lator and Kaybob is relatively front-end loaded. Like we mentioned there with Kaybob being available for that expanded capacity in the second half, well, of course, that would imply that we're doing the work in the first half. And same thing for Lator, getting ready for that Q4 on production date. With respect to future infrastructure build-out, it's not something that we put a fine number out there at this time. When you look at the infrastructure portfolio that we now have the benefit of working with, we look at a big chunk coming available to us in Lator there.

And like I mentioned there, a decent amount coming in Kaybob and some targeted debottlenecking throughout. On top of that, we then also have some available capacity in Gold Creek and Karr because that area was being built out for a pretty good capital program. So when we look at the actual amount that needs to be spent in the out years, without putting a number to it, Dennis, it's going to be lower than we would have expected going into this pre-acquisition just on the basis of, again, being able to utilize the available stuff and move around and fill that white space more effectively.

[Operator Instructions] And your next question will be from Travis Wood at National Bank Financial.

I wanted to hear your thoughts on Lator and so maybe you could kind of walk us through the critical path as you're looking out through the tail end of this year, what type of lead time items you need to work with the partner, additional approvals as you kind of step into Q4 of next year. And then on top of that, what do you think the ultimate productive capacity of that region would be over and above the initial 35 to 40 a day?

Travis, it's Joey Wong one more time. In terms of required approvals and stuff, everything is in hand. So yes, that was kind of part of what set us up for the beat on timing there. And it's important to note that they're in hand early as a result of getting in front of -- at the very start, getting in front of our design basis very early, and that started with a strong understanding of both the technical like the subsurface of the asset base itself. And then some familiarity with building some similar facilities, whether we look at the Musreau facility or some other very similar projects that have been done, we've got the same facility team working on it. So they could draw on a lot of that experience and really compress that initial planning and engineering time so that when we went out for permits, which we -- again, to repeat myself, we have all of them now, but we got those early and that allowed us to start construction early, had a very productive past few months and find ourselves where we're at right now.

So in terms of what we're looking for, for critical path, it's just execution now. Procurement is -- all long leads are placed and deliveries are on track. So really not looking for any other checkmarks except for just following through. Your other question on the ultimate productive capability of the asset base. So Lator Phase 1 is what we're speaking about here right now, 35,000 to 40,000 BOEs per day in that 40% to 50% liquids range. When we look at the entirety of the asset base, the way that we envision it is a likely Phase 2 at some point to bring us up to somewhere in that 85,000 BOEs per day range. And recognizing again that when we first envisioned that, it was outside of the context of having these -- the combined assets that we have, again, the benefit of working with.

So what we intend to do going into the back part of this year and continually refresh that, of course, is evaluate where that next leg of growth comes from. Is it a Lator Phase 2? It's very compelling. We like Lator Phase 1, and we'll definitely like a Phase 2. But again, having a bit of a wealth of opportunities to look at there, we'll put them all against each other and see what makes sense to grow into at the right period of time. Is it more up in the northern part of our acreage? Is it looking into -- depending on what commodity prices look like in the long term? Is it something down in Resthaven, we'll look to make that determination into the future.

Next is a follow-up from Dennis Fong at CIBC World Markets.

I just had one more question, maybe as a follow-up to Travis' on Lator there. Just wanted to ask if you had -- if you could kind of highlight any of the either engineering work or the geology or the facility design that really kind of provides incremental confidence in showcasing an on-plan ramp-up for that region in that facility?

What I'd draw back to, Dennis, is the results that we've had to date. We've called those delineation pads and that's intentional because we're testing different portions of the acreage base there as it pertain to both geological characteristics like how the rock behaves, how it behaves when drilling, how it behaves when fracked and of course, subsequent production. And then what we've also looked to do is craft some of our development program around both the drawdown, assessing what the optimal drawdown rate is and got a team of reservoir engineers that assess what the push and pull between strong initial production compared to ultimately looking at higher ultimate recoveries are and kind of looking to find a balance there.

And then also crafting the -- this year's program around being near existing horizontals to make sure that we've accounted for parent-child interaction appropriately in our plan. So without putting out anything specific there, Dennis, I would definitely say that when you look at the amount of work that's been done, be that through actual drilling, through modeling, through -- I should also mention as well, by the way, we cored a well drilled and cored a well there in the past few quarters there as well. When you look at the amount of work that's gone in, it is quite a high level of rigor. And the good news for us anyways and should give -- has given us anyways quite a bit of confidence is with every either technical evaluation that's been done or observation of physical behavior of the assets, everything has either met or slightly exceeded expectations. So that's really what's given us the confidence to stand behind the forecast there.

Thank you. And at this time, gentlemen, we have no other questions registered. Please proceed.

Thank you, Sylvie, and thanks to each of you on the line today and who continue to support us on our journey. I do want to once again thank our entire Whitecap team for your dedication and efforts over the past 5 month period of time as well as for the full year. We are excited about the opportunity facing us with our company and look forward to updating you on the progress for the balance of '25 and into the future. All the best of each of you, signing off for now.

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