Baytex Energy Corp. Q4 FY2025 earnings call

• Strategic transition: 2025 was a defining year with the closing of the Eagleford sale, repositioning Baytex into a focused Canadian oil producer. Eric Ektor announced Chad Lundberg will succeed him as CEO following the AGM in May. - Operational focus: Committed to technical leadership and disciplined capital allocation. Prioritize heavy oil and DuVernay assets, with enhanced exploration and new play development. Canadian portfolio had 6% organic growth, with solid reserves growth, low F&D costs. DuVernay validated resource potential, reduced well costs, and transitioned to full commercialization. Heavy oil assets have significant acreage and drilling locations, with 2026 plan including well streams, exploration activity, and water flood pilots at Peavine.

In 2025, the Canadian portfolio delivered an annual production of 65,500 BUE per day, excluding dispositions, which represented a 6% organic growth year over year. The company invested $548 million in Canada. The DuVernay had 91,500 net acres, identified approximately 210 drilling locations, and saw production grow to 10,600 BOE per day in the fourth quarter of 2025, a 46% increase from Q4 2024. Heavy oil assets comprise 750,000 net acres and 1,100 drilling locations, with plans to bring 91 heavy oil wells on stream in 2026. For the full year 2025, adjusted funds flow was $1.5 billion and free cash flow was $275 million. In the fourth quarter, adjusted funds flow was $262 million and free cash flow was $76 million, including $35 million in non-recurring expenses related to the Eagleford Disposition.

• 2026 guidance: Annual guidance of 67,000 to 69,000 VOE per day remains unchanged from December, with the high end representing 5% organic growth year over year. There is significant inventory depth and optionality across the portfolio to support the current plan and potentially accelerate growth.

Q: Good morning, everyone, and congrats to the both of you on the transition. I'll start with a question on the growth outlook. You're currently guiding 3% to 5% for 2026, but if we assume that oil prices remain elevated for longer than expected, is there a scenario where growth exceeds the top end of the current range? And then has your overall thought process in terms of high-level deliverables for 2027 changed at all within the last several weeks?

A: It's Chad. On growth, yes, we've guided to a capital program of 550 to 625 million, delivering 67 to 69,000 barrels a day, which represents 3 to 5% production growth. We're actively monitoring the macro picture and situation right now. And we would expect to make any decisions on increased growth at the breakup timeframe. We certainly have the optionality within the portfolio depth and quality to go a little bit harder this year and to your point into 2027. As I said, that'll come, you know, we'll look at that through breakup and make the decisions accordingly. Maybe just a little bit of an example of where we could look to expand the program. potentially another pad in the Duvernay that may look like a drill that gets ducked into next year and completed, or continued expansion in that northeast Alberta fairway where we utilize the two drill rigs that are drilling there today and potentially continue with that second rig. We could also pivot though, just again an example of the depth of the inventory, pivot up into Peace River where we've got some of the exploration work happening and elect to allocate capital up into that region as well. So lots of optionality currently on our radar. We're not moving it too fast, but those will come kind of decisions through breakup.

Q: And then maybe I guess my second question relates to your opening comments on some of the comments that you made on the Peavine water flood opportunity. How material could that be? How do you plan to tackle this relative to some of your peers who are already well down that track? And what could that look like over the next, in terms of deliverables, what could that look like over the next, call it 12, 18 months?

A: So we're deploying two pilot projects this year. One is into the kind of part of the play that we've been actively drilling to this point. So you can expect that, you know, we've produced barrels out of the well that's going to be converted ultimately into an injector. What we're looking for there is just how fast can we fill it up to then pressure support the entire system around it to ultimately drive a lower decline and more barrels out of the ground. The second pilot is in a new development area where we're actually drilling the producers and the injectors simultaneously with each other and we'll turn them on together at the same time. So what's all this mean? I mean, certainly the water flood has been doing great things for our industry. We're not sure what happens with our rock. That's why we've committed to pilots at this point in time. As a reminder, our primary development is very strong, holding 48 of the top 50 wells in the play. And that's really a part and parcel to the incremental pressure that we have in situ in the rock itself. So there's various factors that are maybe unique to our situation that are potentially different from others. If you extrapolate that out, though, to the big picture, we're pretty excited for what it could do if it were to work with respect to base declines and driving more oil out of the ground. What does that mean for the future in the next 18 months? I think we're going to work very hard to try and understand this through kind of end of the year and into the budget process. And then how does that translate into our program next year? It could mean incremental water flood injector activity in 2027. It could mean leaving gaps in our drilling program in between primary producers for the future. And we're just going to have to wait and see, Mano, where we go.

Q: Can you remind me, I should know this, but when was the last time BATEX dabbled in water floods, if at all?

A: Yeah, so I mean, water flood is not new to Baytex at all. We've actually been at it for two decades. Water flood and then also polymer floods. It just depends on the quality of rock and then oil that we're working with. But you could think about it this way, approximately 10% of our heavy oil production, so 43,000 barrels a day in 2025, is water flood derived production. So not new to the story. And it's not foreign to us. We've got the technical capacity and teams to really, we think, advance this forward.

Q: That was very helpful. Thank you. That's all the questions we have from the phone lines. I would like to turn the conference back over to Brian Hector for any questions received online. Please go ahead.

A: Yes, there are a few questions coming through in the webcast, so I'll try and run through those with you here, Chad. Menno spoke to sort of the current WTI price environment, maybe optionality and growth, but another question comes in around, I think it's referencing sort of break-even prices. Is there a WTI price that we would sort of pause the growth scenario, Chad?

A: Well, we set the budget out 3% to 5%, centered at $60 oil, you know, guiding to the high side, more than 5% at 65. And then certainly the flexibility as we've built the program to pull that back, you know, below $60 oil. I think that's how we think about it. Think about our growth. And again, we're just really observing the macro climate right now. Obviously, it's incredibly dynamic and we're taking it in and not going to make any knee jerk moves. But I would remind that we have the optionality and flexibility to move harder if if so desired Q: another question on the operations around our cost of production and just can you speak to the capital efficiencies maybe that you see the business generally chat and steps we can take to continue to work on the cost of production and efficiencies overall A: yeah you know brian i think that gets into how we've laid out the budget for 2026 we've you know started with sustaining capital At $435 million, add the $50 million in growth, $50 million in infrastructure, and then $50 million in exploration. I think when you look into each one of those buckets, they are designed to improve capital efficiency. So I'll just give an example in the DuVernay. The infrastructure spending is at a higher and elevated pace for the next three years and then falls off, you know, post three years to a much lower rate. That flows right through to capital efficiencies. and excess free cash flow to the shareholder. If you look in our investor pack, we've done, again, centered on the DuVernay, pretty good job of delineating the asset, improving the characterization, and then also reducing cash costs. Specifically in 2024, we improved by 11% on the characterization, and then equally so dropped our capital costs by 11%. So both of those flowed straight through to capital efficiency. Maybe just a little bit on the heavy oil program, touched on the $50 million that's allocated to exploration. This is absolutely intended to enhance and lengthen our inventory position. And I think, you know, some of the wells that we released through Q4 of last year up in the Spark and the Sugden area, some of our upper Waseca wells, as we step through that northeast Alberta area and the seven different layers in the Manville stack, We're pretty excited about what it's doing for capital efficiency. I would make this motherhood statement, though, to end the conversation. We're not done. This is something that we do as a company. This is something that our teams are tremendously good at, and this is a huge focus and priority of mine as I step into this role and we move forward into the future from here.

Q: Let's shift gears to a couple of questions and conversations around that we have. It's around $800 million. And Chad, I know we've talked a little bit about the NCIB and the prepared remarks, but how do we see allocating that $800 million going forward?

A: So we've been pretty clear that a good portion of that is going to be returned to the shareholders by way of buyback. Chad Kamikoff in his prepared remarks talked about the NCIB as the as the preferred vehicle over an SIB at this point in time. But we've also been very clear about utilizing some of the proceeds for greenfield, tuck-in, land acquisition, bolt-on style activity in our key and core focus areas. We're still committed to that.

Q: Maybe along those lines then, Chad, Just when you look at buybacks, how would we evaluate the market price, the value, and where we see value in the buyback program itself?

A: Yeah, so I would start here. This company is going to be all about value going forward and an intense focus on how we deliver that value. When we evaluate the buyback specifically, I think there's there's three things we looked at. One is the macro commodity environment. And so we'd like to think about really acting contracyclically and respecting where we're at in the cycle. The second though is just how are we trading relative to our peers? And so as we evaluate that, it looks like we have good potential to grow with respect to how our peers are trading today. And then lastly, and equally as important, is just the intrinsic value of the business. We're constantly running models at different price scenarios with different enhancements that we can put on top of the plan, speaking of the optionality that we have in the deep portfolio set in front of us. And that would inform us on an intrinsic value that all three of those combined would anchor the conversation for how we proceed forward with buybacks. I guess when we look at those all together today, it would still signal that that we are that we are focused on on the buybacks and continuing forward from here.

Q: I guess when we look at those all together today, it would still signal that that we are that we are focused on on the buybacks and continuing forward from here.

A: Excellent and one question in true to check out the copper CFO chat. Can you just talk to our existing hedges in place? Maybe WTI and WCS with the policy will look like going forward.

A: Sure, we had hedges in place kind of through the back half of last year. Collar structures, we'll put floors at 60. Through the transaction, we maintain those. So we'd be roughly, you know, I'll call it 60% hedge on TI Q1 and about 50, 45 to 50% hedge in Q2. You know, nothing has changed policy-wise. I think we always talked in the past about a strong balance sheet is the best hedge you can have. So going forward, I think uh we obviously have a very pristine balance sheet i wouldn't expect us to be uh uh looking to hedge wti contracts uh really in the future uh given the balance sheet we have today that being said i think we can still look at hedging wcs contracts we're 45 percent hedged on w or on wcs this year at about 13 we still think that's an important piece of business to keep hedging uh to kind of prevent any uh financial impact from major blowouts. So summary, WTI, those will be rolling off here at the end of June. I wouldn't expect us to be that active in the hedging market on WTI, maybe in specific circumstances, continue to kind of hedge differentials.

Q: Okay, great. I think that's going to wrap up the large portion of questions coming in from the webcast. I would like to thank everyone for joining us. uh for those who submitted webcast questions that we didn't get to address please reach out to our investment relations team and we'll follow up directly thanks again for your time today and have a great day this concludes today's conference call you may disconnect your lines thank you for participating and have a pleasant day