Baytex Energy Corp.

Good day, everyone. Thank you for standing by. This is the conference operator. Welcome to the BATEX Energy Corp. Second Quarter 2025 Financial and Operating Results Conference Call. As a reminder, all participants are in a listen-only mode. The conference is being recorded. After the presentation, there will be an opportunity for analysts to ask questions. To join the question queue, you may press star and then 1 using a telephone keypad. You may also submit questions in writing at any time using the form in the lower section of the webcast frame. Should you need assistance during the conference, you may see a conference operator by pressing star and zero. I would now like to turn the floor over to Brian Echter, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

Thank you, Jamie. Good morning and welcome to Bay Texas second quarter 2025 earnings call. I am joined today by Eric Greger, 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.

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 Eagleford team delivered two more strong refracts at half the cost of new wells. The commodity backdrop in Q2 was soft, with WTI averaging US $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.

Thanks, Eric. We delivered second quarter financial results consistent with our full-year plan. Adjusted funds flow was $367 million, or 48 cents 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 U.S. $41 million of our 8.5% long-term notes during the quarter as part of our systematic approach to debt reductions. We maintain substantial financial flexibility with U.S. $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 Lumberg for our operating results.

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 BUE per day per well with 3,800 meter completed lateral links. The second pad came on stream through early July with similar lateral links and over the last 26 days has averaged 1,264 BUE per day per well. Our third pad is expected on stream in September. The performance of our first two 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 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 two additional refracts, with initial rates comparable to our broader development program at approximately half the cost. With 300 refract 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 Lloyd Minster, 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.

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 Eagleford 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 toward crude oil and liquids. Every US $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 BATEX to deliver sustainable long-term value for shareholders. Operator, we're ready for questions.

We will now begin the analyst question and answer session. To join the question queue, you may press star and then one on your telephone keypads. You will hear a tone acknowledging your request. To submit your question in writing, please use the form in the lower right section of the webcast frame. If you are using a speakerphone, we do ask that you please pick up your handset before pressing the keys. To withdraw your questions, you may press star and 2. We will pause for a moment as callers join the queue. Our first question today comes from Amir Arif from ATB Capital. Please go ahead with your question.

Thanks. Good morning, guys. 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?

Yeah, thanks, Amir. Good morning. The average well cost so far this year has been running right at $12.5 million. So for a 12,000-foot lateral, 12,500-foot lateral, that's right at $1,000 per completed lateral foot. And, you know, 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.

Got it. And based on the comments of eventually moving to commercialization in 26, 27, should we think about like one-week program for 26, like 12-month program next year?

Well, so... Yes, we are eventually moving in 2027 to a one-rig levelized program. We think that will generate 18 to 20 wells per year. So a single rig running around the calendar, Amir, will be an 18 to 20 well pace of development. Next year in 2026, we're targeting 12 to 15 wells. You know, it kind of depends on, you know, 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 one rig will be higher than 12, so next year won't quite yet.

Okay, I appreciate that. I appreciate the color there. Just switching over to the Eagleford, The IP weights are fantastic, and those are essentially like a new well rate. Is the decline rate different post the refrax? It's still a little early.

Yeah, yeah. So, yeah, the early rates are strong. The pressure performance is strong. Everything we can see so far within reservoir characteristics, you know, dynamic testing indicates to us that We're touching all new reservoirs, and that's really encouraging. But it's a little bit too early on the two refracts in 2025 to know, you know, really with data specificity around decline rates. So far, so good. They feel very strong, and we have every indication that we're touching new reservoir in these refracts. So that's strong.

Okay. And then just one final question, if I can. I'm pleasantly surprised to see that your cost for lateral foot even improved in Eagleford by a meaningful amount, 10% or 11%. What are you doing differently over there? I would have thought it's more of a mature play where you'd just be getting a few percentage point improvements per year.

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?

Okay. Yeah, I mean, it's a combination of two things. We're seeing some relief from our service partners with just service cost reductions. You know, most notably, you see... Drill rig activity levels and fracture 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 gain. You know, we like to measure those in lateral footage per day. or completion pump hours per day. In half one this year, we saw another marked improvement over 24. 23 was better than 2.2. 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 one 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 right on site. And so that's been a meaningful savings as well. So savings, efficiencies, and just a little bit different plumbing on lease for how we're capturing it, Amir.

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?

Oh, I think, you know, we're in the 50% both sides. Okay. And, you know, I would just point out efficiencies are sticky, and that's why we get more excited about them, you know, because they last through all parts of the commodity cycle.

Sounds great. Well, congrats on the good operating results. Thanks.

Thank you.

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 Echter for questions received online.

Great. Thanks, Operator. I do have several questions coming in on the webcast, some from our analysts and a few from investors as well. Continuing with the Pemba and the Duvernay performance, can you speak to the variability across the three wells? So we talked about the performance of the 701 pad. There were three wells on that pad. Can you speak to the variability? Was there much variability in each of those three wells?

Yeah, so I'm going to let Chad comment on this. Chad Lundberg, over to you.

Yeah, so 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 trend. EUR pattern ultimately through time. But the reality is there is going to be differences throughout the play. I think what we're most excited about is 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.

I have one more question related to the DuVernay, and that's on the infrastructure side. Can we discuss the potential infrastructure spending needed to expand the production in the Pembina DuVernay?

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, two 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 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 gasier-style development. So we've got gas pipe all through the area, and then we've got a large gas processing facility with Kiara, 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.

I'm going to switch to the Eagle for a minute here. We talked about the refracts in the quarter. Eric, how are we looking to layer in capital on the refract opportunity? and the depth of the inventory there?

Yeah, so we are very excited about the refracs. The team has gone from proof of concept last year to 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.

Okay, Eric, on the non-operated piece of our Eagleford asset, 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?

Yeah, we've got a great relationship with Conoco. We had a great relationship with Marathon. As a significant working interest partner, in those CARNs 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.

Okay, and I've got one more question to ask today on the financial side. I'm going to bring Chad Kamakoff into the conversation. Chad, how are we thinking about our hedging strategy going forward?

Thanks, Brian. Yeah, our hedging strategy I don't think has changed. So we're barely 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 based on the balance sheet and asset kind of break, you know, where we started flowing back capital below that $60 floor level. So feeling good about where we have 25. As we look into 2026, we're lately headed at this point, but still looking at that same framework where we want to have that $60 put floor. Given where prices are today, the calls aren't as high as they were at one time. But we've started layering in a little bit here into Q1. You know, when prices have spiked, the backwardation of the curve has still been pretty strong. But we're trying to layer in 60 by kind of, you know, low, mid 70s where we can get them. And we'll continue to do that through the balance of this year. I'd like to have 40% hedged by the end of this year if we walk into 2026. All right.

Thanks, Chad. And that does wrap up today's call in the Q&A portion. I'd like to thank everyone for joining us. Thanks again for your time today and have a great day.

This brings to a close today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.