Whitecap Resources Inc. (WCP) Earnings Call Transcript & Summary

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 component. 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 were $925 million was also a record for what cap. By these incremental firms, we will continue to execute our countercyclical approach to prefund 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 have reduced our net debt by $900 million to $2.5 billion or 2.5x debt to cash flow. From an operational perspective, Whitecap delivered another strong operating quarter, with production averaging 38,894 BOE per day, comprised of [indiscernible] barrels of liquids, slightly under 900 million a day 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, which bring up a breakup now behind us, activity is increasing as planned. We expect to use approximately 12 rigs for 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. The new oil performance, base optimization and high infrastructure utilization contributed positively during the quarter. These results reflect consistent application of our integrated development workflow which combines the expertise of our technical and operating teams with a deep proprietary data set and rigorous feedback loops from each well pad and pad 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 guidance range. I will now pass the call over 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 [indiscernible] 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 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 the light oil and condensate volumes realizing a premium to WTI. Total liquids accounted for approximately 93% of our revenue during the quarter despite being only 61% of total production. 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 of $40 -- or $4 per Mcf. For 2027, we have hedged 26% of our crude -- 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 Verint 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 aggregates. 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 tons of proppant placed per day during completions are now 31% and 13% above historical levels, respectively, compared with 27% and 12% and disclosed in the first quarter, demonstrating continuous improvement and better capital efficiency. [indiscernible] construction of the 413 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 path prior to the end of the year. Turning to CAR, 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 frac geometry broadly conforms 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 tons 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 refers the 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 CAR 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 continued 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 [indiscernible] 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 [indiscernible] 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 this application in future [indiscernible] development. Moving over to Saskatchewan. Our assets continued 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 multi-stage 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, 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 advantage as 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 Baron transaction on May 12, 2025, and the combination is delivering measurable improvements across the asset base. Since closing, capital efficiency is improved by approximately 12% from $21,000 per BOE to $18,500 per BOE flowing BOE, while operating costs have declined by approximately 13% from $1,350 on a combination basis to below $12 per BOE. These improvements demonstrate the benefits of applying Wet Cap's operating practices, technical expertise and capital discipline across our expanding portfolio. The case strength of our portfolio is its exposure to light oil, 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 front well. The outlet for Western Canada, light oil and condensate remains very constructive. expanded export capacity and growing demand for secure North American energy supply are expected to support market access and pricing for Canadian light oil. As one of the largest light oil and condensate producers in Western Canada at approximately 120,000 barrels per day. 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 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 food and debt levels. Whitecap has the inventory depth, premium product exposure, financial strength and strong technical capabilities to generate sustainable shareholder returns and capitalize on the growing demand for secure Canadian energy. With that, I will now turn the call over to operator, Sylvie, for any questions.

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

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 Veran transaction. So how should we start to manage this in terms of -- so 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 it's kind of staying with the plan in terms of 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 -- 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, Charles. 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 what was 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 along -- 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 Verint, it's been broad, like I say there. And it comes as a result of integrated development workflow we talk about, and Chris spoke to that about how plays like the Charlie there, which is a legacy Whitecap play, still seeing improvements on that play. by looking to the fundamentals of the design 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 your question here to lean into any area more than another? The answer is 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.

I think you hit it there, Joey, for sure. I mean, specifically on the conventional side, I mean, I think it's just great to see that we continue to drive forward with just 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 optimization, in particular in the Charlie side.

Appreciate that from everybody. And then my 0.5 of the question is, if you can humor me is with -- 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. -- it's a full question. I don't know if that's a has. But anyway, I have 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 the 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 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 -- we'll be looking to do that at least in the near term.

Next question will be from Michael Harvey at RBC.

Yes, sure. 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 to the conflict in the Middle East. So what that will provide us is really maximum optionality to deploy that -- 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.

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 on the design side. And we've spoken at relative linked to some of the design changes we made with respect to how we land the wells vertically, the [indiscernible] 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 has referenced earlier about the maximum optionality 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 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% of the minimum and 5% at the higher side. But it allows us that full flexibility. We live in the world at a very unstable world at this particular time. So oil prices, as Thanh referenced earlier on, the -- 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 -- you have to think about in that context. And when we're trying to develop as much shareholder value as we can. We have to think about what's the longer-term outlook of commodity prices, both on crude oil that are 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 support. -- that requires condensate. So their needs much more cores if we're going to grow our 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. those are all the backdrop. It's not just one solution, and we have to look at it holistically from many different components. Anything else to add, Thanh?