Baytex Energy Corp. (NYSE:BTE) Q2 2025 Earnings Call Transcript

Baytex Energy Corp. (NYSE:BTE) Q2 2025 Earnings Call Transcript August 1, 2025

Operator: Good day, everyone. Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. Second Quarter 2025 Financial and Operating Results Conference Call. [Operator Instructions] The conference is being recorded. [Operator Instructions] I would now like to turn the floor over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

Brian G. Ector: Thank you, Jamie. Good morning, and welcome to Baytex’s Second Quarter 2025 Earnings Call. I am joined today by Eric Greager, our President and Chief Executive Officer; Chad Kalmakoff, our Chief Financial Officer; and Chad Lundberg, our Chief Operating Officer. Before we begin, please note that our discussion today contains forward-looking statements within the meaning of applicable securities laws. I refer you to the advisories regarding forward-looking statements, oil and gas information and non-GAAP financial and capital management measures in yesterday’s press release. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. And after our prepared remarks, we’ll open the call for questions from analysts. Webcast participants can also submit questions online, and we will address as many as time permits. With that, let me turn the call over to Eric.

Eric Thomas Greager: Thanks, Brian. Good morning, everyone. We delivered solid operational and financial results in the second quarter that reflect the quality of our assets as well as our focus on operational excellence. In the Pembina Duvernay, we achieved the highest 30-day peak oil rates recorded in the West Shale Basin. These results validate our technical and operational advances, and help demonstrate the exceptional resource potential within our portfolio. Beyond the Duvernay, the teams consistently delivered solid execution across our operations. Heavy oil production grew by 7% quarter-over-quarter, while our Eagle Ford team delivered 2 more strong refracs at half the cost of new wells. The commodity backdrop in Q2 was soft with WTI averaging USD 64 per barrel.

In this volatile environment, we remain focused on capital discipline, prioritizing free cash flow and reducing net debt. Our second quarter results demonstrate our resiliency through commodity price cycles, while maintaining capital flexibility. Let me turn the call over to Chad Kalmakoff for our financial results.

Chad L. Kalmakoff: Thanks, Eric. We delivered second quarter financial results consistent with our full year plan. Adjusted funds flow was $367 million or $0.48 per basic share, and we generated net income of $152 million. We generated $3 million in free cash flow and returned $21 million to shareholders, including $4 million in share repurchases and $17 million in quarterly dividends. Balance sheet strength remains a priority. Net debt decreased $96 million or 4% to $2.3 billion, supported by a strengthening Canadian dollar. We repurchased USD 41 million of our 8.5% long-term notes during the quarter as part of our systematic approach to debt reduction. We maintain substantial financial flexibility with USD 1.1 billion in credit facility capacity that is less than 25% drawn and matures in June 2029.

Our long-term debt maturity profile provides significant runway with our earliest note maturity in April of 2030. Let me turn the call over to Chad Lundberg for our operating results.

Chad E. Lundberg: Thanks, Chad. We’re pleased with the operating performance across our portfolio. Production averaged 148,095 BOE per day, a 2% increase in production per share compared to the same quarter last year. Exploration and development expenditures totaled $357 million, consistent with our full year plan, and we brought 67 wells on stream. In the Pembina Duvernay, our first pad achieved average 30-day peak production rates of 1,865 BOE per day per well with 3,800- meter completed lateral length. The second pad came on stream through early July with similar lateral lengths. And over the last 26 days has averaged 1,264 BOE per day per well. Our third pad is expected onstream in September. The performance of our first 2 pads has exceeded initial rate expectations.

With the first pad delivering the highest 30-day peak oil rates to date in the West Shale Basin. These results demonstrate our continued advancement in drilling and completions performance. In addition to well performance, we achieved a 12% improvement in drilling and completion costs compared to 2024. These efficiency gains strengthen well economics and further support our capital allocation decisions. With 140 net sections and approximately 200 locations identified, we plan to transition to full commercialization through ’26 and into ’27. This means we would target drilling 18 to 20 wells per year, resulting in production ramping to 20,000 to 25,000 BOE per day by ’29, 2030. In the Eagle Ford, we brought on stream 15 wells, while realizing an approximate 11% improvement in drilling and completion costs.

We delivered 2 additional refracs with initial rates comparable to our broader development program at approximately half the cost with 300 refrac opportunities identified across our acreage. This program extends asset duration, while delivering strong capital efficiency. Our heavy oil operations continue their strong performance with production up 7% quarter-over-quarter. We brought on stream 43 wells across Peavine, Peace River and Lloydminster continuing to demonstrate the capital-efficient development of these assets. Our team continues to focus on safe and efficient development across our portfolio as we progress through the year. Let me turn the call back to Eric for his closing remarks.

Eric Thomas Greager: Thanks, Chad. Our second quarter results reinforced the quality of our asset portfolio and our ability to execute through volatile market conditions. The top performance in the Pembina Duvernay highlights the asset’s strong value and growth potential, while our heavy oil operations continue delivering strong returns and our Viking and Eagle Ford assets provide reliable cash flow and asset duration. We remain committed to rigorous capital allocation and regularly evaluate opportunities within our portfolio to maximize shareholder value. The operational achievements delivered in the second quarter provide us with valuable options as we continue to optimize our plans. Based on forward strip pricing, we expect to generate approximately $400 million of free cash flow in 2025 with the majority weighted to the second half of the year given our production and capital spending profile.

We plan to allocate 100% of free cash flow to debt repayment after funding quarterly dividend payments, targeting net debt of approximately $2 billion by year-end. Looking ahead, our oil-weighted production profile provides significant exposure to oil price upside with approximately 84% of our production weighted towards crude oil and liquids. Every USD $5 per barrel change in WTI impacts our annual adjusted funds flow by approximately $225 million on an unhedged basis. This positions us well to benefit from any oil price recovery. We remain focused on operational excellence, financial discipline and positioning Baytex to deliver sustainable long-term value for shareholders. Operator, we’re ready for questions.

Q&A Session

Operator: [Operator Instructions] Our first question today comes from Amir Arif from ATB Capital.

Laique Ahmad Amir Arif: A couple of quick questions. Just with the 12% improvement that you’re citing in the Duvernay, can you let us know what your average well cost is averaging up there?

Eric Thomas Greager: Yes. Thanks, Amir. The average well cost so far this year has been running right at $12.5 million. So for a 12,000-foot lateral, a 12,500-foot lateral, that’s right at $1,000 per completed lateral foot. And that’s, I think, affords us continued opportunities for improvement as well. So we’re targeting a lower value over time, but that’s kind of where we stand today.

Laique Ahmad Amir Arif: Got it. And based on the comments of eventually moving to commercialization in ’26, ’27, should we think about like 1 rig program for ’26 like 12-well program next year?

Eric Thomas Greager: Well, so yes, we are eventually moving in 2027 to a 1-rig levelized program. We think that will generate 18 to 20 wells per year. So a single rig running around the calendar, Amir be an 18 to 20 well base of development. Next year, in 2026, we’re targeting 12 to 15 wells. It kind of depends on the balance of the year and kind of commodity price, let’s say, in 2026. But we’re shooting for 12 to 15, and that continues to step toward full commercialization. We’re very pleased. Very encouraged by the opportunity for this commercialization and moving toward full development. But 1 rig will be higher than 12. So next year won’t quite get…

Laique Ahmad Amir Arif: Okay. I appreciate that. I appreciate the color there. Just switching over to the Eagle Ford. The IP rates are fantastic. I mean those are essentially like a new well rate. Is the decline rate different post the refracs?

Brian G. Ector: It’s still a little early.

Eric Thomas Greager: Yes. Yes. So yes, the early rates are strong. The pressure performance is strong. Everything we can see so far within the reservoir characteristics, dynamic testing indicates to us that we’re touching all new reservoir. And that’s really encouraging. But it’s a little bit too early on the 2 refracs in 2025 to know really with data specificity around decline rates. But so far, so good. They feel very strong and we have every indication that we’re touching new reservoir in these refracs. So that’s strong.

Laique Ahmad Amir Arif: Okay. And then just one final question, if I can. Pleasantly surprised to see that your cost per lateral foot even improved in the Eagle Ford, like by meaningful amount, 10% or 11%. What are you doing differently over there? Like I would have thought it’s more of a mature play where you’d just be getting a few percentage point improvements per year?

Eric Thomas Greager: Well, I’m going to pitch that one over to Lundberg. Chad, why don’t you comment on kind of some of the progression around drilling and completions improvements on the CapEx side and efficiency improvements as well.

Chad E. Lundberg: Okay. Yes. I mean it’s a combination of 2 things. We’re seeing some relief from our service partners with just service cost reductions, most notably, you see drill rig activity levels and frac activity levels in the U.S. It’s no secret that they’ve been dropping, significantly. So we have seen some relief from our service companies on the cost side. We’re excited about that. We’re probably more pleased with just the continued efficiency gains. We like to measure those in lateral footage per day or completion pump hours per day. In half 1 this year, we saw another marked improvement over ’23 — ’24, ’23 was better than Q2. So we just continue to see improvements on the efficiency side. Lastly, though I’d point to, we made a conscious effort to switch late last year and then through most of half 1 this year to field gas on the frac side.

And so instead of burning diesel to power the equipment to put the net energy into the ground, we’re able to plug in to the gas flows rate on site. And so that’s a bit of meaningful savings as well. So savings efficiencies and just a little bit different plumbing on lease for how we’re capturing it, Amir.

Laique Ahmad Amir Arif: Okay. And then, Chad, if you had to break out that 11% in terms of service cost reduction versus these efficiencies, is there a rough number that you could give?

Chad E. Lundberg: I think we’re in the 50% both sides. And so and I would just point out efficiencies are sticky, and that’s how we get more excited about them because they last through all parts of the commodity cycle.

Operator: And ladies and gentlemen, with that, we’ll be closing the question-and-answer session from the phone lines. I’d like to turn the floor back over to Brian Ector for questions received online.

Brian G. Ector: Great. Thanks, operator. I do have several questions coming on the webcast. Some from our analysts and a few from investors as well. Continuing with the Pembina Duvernay performance, can we speak to — Eric, can you speak to the variability across the 3 wells. So we talked about the performance of the 701 pad. There were 3 wells on that pad. Can you speak to the variability? Was there much variability in each of those 3 wells?

Eric Thomas Greager: Yes. So I’m going to let Chad comment on this, Chad Lundberg, over to you.

Chad E. Lundberg: Yes. So on the — I mean on the pad itself, they’re pretty localized wells. We see consistent performance across them. And then the differences in rates between the pad in the south, the pad in the North. I mean, let’s face it, there’s rock characteristic differences, reservoir characteristic differences. And then we are also trialing some different ways that we — not so much complete the wells, but maybe more on the facility side, the flowback side. And so while we see an IP difference, we think that these naturally will trend to a similar EUR pattern ultimately through time. But the reality is there’s going to be differences throughout the play. I think what we’re most excited about is these — both these pads are exceeding kind of certainly our expectations and our internal curves at this point, but it’s early. I would just caveat it with it’s early, and we’ll see where they go from here.

Brian G. Ector: All right. One more question related to the Duvernay. That’s on the infrastructure side. Just can we discuss the potential infrastructure spending needed to expand the production in the Pembina Duvernay?

Chad E. Lundberg: Yes. I mean I think we’ve got that fairly well characterized right now. I mean, you saw our Gibson deal that we announced last quarter or 2 quarters ago, where they’re taking some of the infrastructure burden off of us. We’re still pleased with the agreement and the synergies that we’re creating with Gibsons. We think facilities, no doubt are going to be somewhat front-end loaded. We think about it as $25 million to $30 million a year for these early years, liberating itself to a lower rate in the out years. And I think the last note I’d make is some of the major facility when you think about unconventional resource, major facility spend is on gas plants and gas handling. The benefit we have is we’re overlaying a cobweb of earlier development that was gassier style development.

So we’ve got gas pipe all through the area. And then we’ve got a large gas processing facility with Keyera, one of our partners that’s not full. We don’t anticipate that it fills through the life of the place. So it’s got significant capacity to handle all the molecules we anticipate flowing into the future. Said differently, we don’t have to go out and build what we would think as the largest capital contributor to these unconventionals in just the gas processing.

Brian G. Ector: Let’s switch to the Eagle for a minute here. We talked about the refracs in the quarter. Eric, how were we looking to layer in capital on the refrac opportunities in the Eagle Ford, given the depth of the inventory there?

Eric Thomas Greager: Yes. So we are very excited about the refracs. The team has gone from proof of concept last year to 2 really strong successful refracs to follow up the successful proof of concept last year. So couldn’t be more excited. We’ve got 300 opportunities identified in our current base, and we intend to step up the pace of our refracs, bringing those into the program with greater frequency. So as it stands today, the way we see 2026 is somewhere in the 6 to 10 refracs range. And again, given the economic performance of these and the capital efficiency, we’re going to lean on that.

Brian G. Ector: Okay. Eric, on the nonoperating piece of our Eagle Ford asset, those — that program is now operated by Conoco. They’ve been operating the wells for about a year post their acquisition of Marathon. Can you speak to any changes in their process or approach with regard to the non-op asset? And our relationship with the operator?

Eric Thomas Greager: Yes, we’ve got a great relationship with Conoco. We had a great relationship with Marathon as a significant working interest partner in those Karnes mutual interest areas. We work closely with them. And across the organization, we get good information from them. They’re very thoughtful about how they develop. They’re very thoughtful about how they plan. They were thoughtful and diligent in their timing of providing us the 2025 program. They told us to use the one we had until we heard otherwise. They’ve delivered a new ’25 plan to us, and we’re satisfied with it. So we believe that we’ve got a strong relationship, and we believe that the development is going to continue moving forward, and we’re very comfortable with the plans that we’ve seen.

Brian G. Ector: Okay. And I’ve got one more question asked today on the financial side. I’m going to bring Chad Kalmakoff into the conversation. Chad, how are we thinking about our hedging strategy going forward?

Chad L. Kalmakoff: Thanks, Brian. Yes, I don’t — our hedging strategy, I don’t think has changed. So we’re fairly hedged here in 2025. On the oil side, we’ve been targeting $60 floors and then selling calls on top of that to kind of fund the puts where we can. So generally speaking, we use it as a bit of an insurance product that $60 floor kind of base in the balance sheet and asset kind of where we start flowing back capital below that $60 floor level. So feeling good about where we have ’25. As we look into 2026, we’re lightly hedged at this point, but still looking at that same framework where we want to have a $60 a foot floor. Given where prices are today, the calls aren’t as high as they were at one time. But we started layering in a little bit here in Q1.

When prices kind of spiked, the backwardation of the curve has still been pretty strong. But we’re trying to layer in 60 by kind of low, mid-70s where we can get them, and we’ll continue to do that through the balance of this year and look to have 40% hedged by the end of this year as we walk into 2026.

Brian G. Ector: All right. Thanks, Chad. And that does wrap up today’s call and the Q&A portion. I’d like to thank everyone for joining us. Thanks again for your time today, and have a great day.

Operator: This brings to a close of today’s conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.