Good day, everyone. Thank you for your patience. This is the conference operator. Welcome to the Baytex Energy Corp. Second Quarter 2025 Financial and Operating Results Conference Call. The conference is being recorded. I would now like to turn it over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please proceed.

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.

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.

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.

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 on stream 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.

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.

Our first question today comes from Amir Arif from ATB Capital.

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?

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, 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 1 rig program for '26 like 12-well program next year?

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, would 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...

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?

It's still a little early.

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.

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 a 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?

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

We are experiencing relief from our service partners due to service cost reductions, particularly in drill rig and frac activity levels in the U.S., which have significantly decreased. This has led to lower costs from our service companies, and we are excited about this development. We are especially pleased with the ongoing efficiency gains, which we measure in terms of lateral footage per day and completion pump hours per day. In the first half of this year, we observed a considerable improvement compared to 2023, with 2023 performing better than the second quarter. We continue to see advancements in efficiency. Additionally, we've made a deliberate decision to switch to field gas for fracking instead of using diesel to power our equipment, allowing us to tap into the gas flows on site. This change has resulted in meaningful savings as well.

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?

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.

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.

Great. Thanks, operator. I have several questions from the webcast, including some from our analysts and a few from investors. Continuing with the Pembina Duvernay performance, Eric, can you discuss the variability across the three wells? We talked about the performance of the 701 pad which has three wells. Can you elaborate on the variability among those wells?

Yes. So I'm going to let Chad comment on this, Chad Lundberg, over to you.

Yes. The wells on the pad are quite localized, and we observe consistent performance among them. There are differences in rates between the southern and northern pads due to variations in rock and reservoir characteristics. We are also experimenting with different approaches on the facility and flowback sides. While we see differences in initial production, we expect these to eventually align to a similar ultimate recovery pattern over time. However, there will still be variations across the play. What excites us is that both pads are currently surpassing our expectations and internal projections, but it's important to note that it is still early, and we will have to see how they perform moving forward.

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?

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.

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?

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.

Okay. Eric, regarding the nonoperating aspect of our Eagle Ford asset, that program is now managed by Conoco. They have been operating the wells for about a year since acquiring Marathon. Can you discuss any changes in their process or approach concerning the non-operated asset? Additionally, how is our relationship with the operator?

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.

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?

Thanks, Brian. Yes, I don't think our hedging strategy has changed. We're well-hedged for 2025. On the oil side, we've been aiming for $60 floors and then selling calls on top of that to fund the puts when possible. Overall, we use it as a kind of insurance product, with the $60 floor serving as a base in our balance sheet and asset management, especially when capital starts flowing back below that $60 floor. I feel confident about our position for 2025. As we look towards 2026, we are lightly hedged at this moment but still aiming for that same framework with a $60 floor. Given current prices, the calls aren't as high as they used to be, but we've started incorporating a bit of that in Q1. When prices spiked, the backwardation of the curve remained strong. We're trying to establish a $60 floor in the low to mid-70s range where possible, and we'll continue to do this throughout the year, aiming to have 40% hedged by year-end as we prepare for 2026.

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.

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