WCP.TOWCP.TOTSX
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Operator: 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.
Grant Fagerheim: 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.
Thanh Kang: 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]
Joey Wong: 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.
Chris Bullin: 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.
Thanh Kang: 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.
Grant Fagerheim: 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: [Operator Instructions]. First will be Sam Burwell at Jefferies.
George Burwell: 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?
Grant Fagerheim: 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.
Thanh Kang: 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.
George Burwell: 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?
Thanh Kang: 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.
Operator: Next question will be from Phillips Johnston at Capital One Securities.
Phillips Johnston: 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?
Thanh Kang: 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.
Phillips Johnston: 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?
Joey Wong: 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: [Operator Instructions]. Next, we will hear from Michael Spiker at HTM Research.
Michael Spyker: 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?
Grant Fagerheim: 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.
Operator: Thank you. And at this time, gentlemen, we have no other questions registered. Please proceed.
Grant Fagerheim: 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.
Operator: 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.