Baytex Energy Corp. (BTE) Earnings Call Transcript

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp Third Quarter 2026 Financial and Operating Results Conference Call. [Operator Instructions] and the conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Chris Lessoway, Vice President, Finance and Treasurer. Please go ahead.

Thank you, operator. Good morning, and welcome to Baytex's Third Quarter 2026 Results Conference Call. Joining me today are Chad Lundberg, our President and Chief Executive Officer; Kendall Arthur, our Chief Operating Officer; and Chad Kalmakoff, our Chief Financial Officer. 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. We will open the call for questions after our prepared remarks. Webcast participants are able to submit questions online. With that, let me turn the call over to Chad Lundberg.

Good morning. We continue to execute our strategy with strong performance across our portfolio unlocking an opportunity rich set of growth options driving long-term value for shareholders. In 2026, we have improved capital efficiency, reduced operating costs and lowered our decline rate and breakevens. Most importantly, safety performance has been strong. I want to thank our teams across the operations for their continued commitment to safety. The improvements we've made have translated into an accelerated growth plan, improved capital efficiency, lower costs and execution across the Duvernay and heavy oil portfolio enable and increase this 2026 capital program and are the foundation of a higher growth plan for 2027 through 2029. This acceleration is driven by efficiency gains not a change in our commitment to capital discipline. Execution of our strategy once again illustrated by our Q3 results. Production averaged 71,600 BOE per day up 5% from third quarter of 2025 and in line with our full year plan. We delivered record Duvernay production of 12,800 BOE per day continued to perform across the heavy oil portfolio and generated $139 million of free cash flow. We also returned $165 million to shareholders during the quarter through share repurchases and our base dividend while exiting with a net cash position of $522 million. For 2027, we expect production of 76,000 to 79,000 BOE per day, representing 7% to 11% annual growth with exploration and development expenditures of $775 million to $850 million. This is the first year of full Duvernay commercialization, which drives Q4 to Q4 growth of 15%. This program achieved a sustaining capital breakeven of $50 per barrel in 2027, down from $52 in 2026 which allows us to continue returning capital to shareholders. Our updated 3-year outlook has improved and now target 8% to 10% annual production growth supported by capital expenditures of approximately $800 million. This plan is built to deliver, having exceeded our 15% total shareholder return target through the third quarter of 2026. We expect to achieve it again in 2027. At a mid-cycle, WTI per race of $70 per barrel, we expect remain a net cash financial position throughout the 3-year plan, funding production growth, continued share repurchases and the base dividend. Kendall will take you through the operating performance. Chad Kalmakoff will cover off our financial position and capital allocation in more detail. Kendall, over to you.

Thanks, Chad. Third quarter production averaged 71,606 BOE per day and exploration and development expenditures were $186 million, both in line with our full year plan. Beginning with the Duvernay, our second pad of 2026, a 5-well pad on our Northern Pembina acreage was brought on stream in late August. The wells generated average 30-day initial production rates of 1,489 BOE per day per well, including 973 barrels per day of oil. Drilling and completion performance continues to improve. Full link 2026 wells achieved drilling completion cost of $930 per foot of completed lateral, better than budget at 11% lower than 2025. The shorter cycle times allow us to add 2 drills in the fourth quarter, taking 2026 program to 19 wells drilled, 13 wells are expected to onstream in 2026, with the remaining 6 brought onstream in 2027. Our third Duvernay pad of 2026, a 4-well pad in Northern [ Pembina ] is completed and now on stream. Tuck-in acquisitions completed during the year increased our Duvernay land position by 16% to 106,000 net acres. With efficiency gains in expanded inventory, we could now grow the Duvernay to 25,000 BOE per day 1.5 years faster than our previous plan that retained over 15 years of old flat inventory at that level. Turning to heavy oil, 5 rigs were active during the third quarter across Pavin Peace River, Boyd Minster and Moreno with strong well performance and efficiency gains realized in 2026, we now expect to bring approximately 109 [indiscernible] oil wells on stream in 2026 including 5 additional Clearwater wells at [indiscernible] and 4 additional wells at the Peace River. We are also advancing enhanced oil recovery. The expanded fourth quarter program includes $13 million for additional polymer flood development at Boidminster, with production expected in the second quarter of 2027. Looking to 2027, our operating plan advances each of the core businesses. Roughly 40% of our 2027 capital investment goes to the Duvernay with the balance directed to heavy oil and Viking. In the Duvernay, we plan to bring 21 wells on stream and grow average production to approximately 18,000 BOE per day, targeting a fourth quarter exit rate of 22,000 to 23,000 BOE per day. The Viking will run a fiction 1-rig drilling program with plans to bring 66 net wells on stream in 2027. In heavy oil, we plan to bring approximately 130 wells on stream, including 32 at [indiscernible] 78 [indiscernible] and approximately 20 at Peace River. We expect heavy oil production to grow modestly to approximately 48,000 BOE per day. Our updated 3-year outlook maintains this pace of development. Annual growth at 8% to 10% takes corporate production to approximately 92,000 BOE per day by 2029. Annual capital expenditures are expected to average $800 million through the plan. Production in the Duvernay will grow approximately 35% per year through this plan, achieving the targeted 25,000 BOE per day level in the second half of 2028. We are targeting further improvements in drilling and completion costs to further improve free cash flow generation from the Duvernay. Heavy oil production is expected to grow modestly while contributing significant free cash flow through the plan. Our deep inventory of primary development opportunities, supported by continued delineation in Northeast Alberta and expanded and hassle recovery provides a strong foundation for the business. Notably, this plan could be enhanced with waterflood in the Clearwater and Gemini [indiscernible] deluge development. At [indiscernible], 5 waterflood patterns are currently injected at expected rates with 6 expected to begin in the fourth quarter. We expect to see a response on the pilots by mid-2027. We have also completed drilling a REX waterflood pilot at Morinville, with injection scheduled to begin in the fourth quarter. In 2027, we are advancing technical characterization, engineering and design for Gemini Modular SAGD project with a target FID in the second half of the year. Gemini has approximately 300 million barrels of oil in place, a successful pilot completed in 2014 and regulatory approval for a 5,000 barrel per day first phase. Waterflood and thermal development can strengthen our business by increasing recovery from our existing resource base while adding sustainable production of free cash flow generation. Our 3-year outlook is about building stronger or profitable business, disciplined capital allocation directs investment towards opportunities that improve returns and strengthen free cash flow. Advancing an enhanced ore recovery and thermal is expected to moderate declines and reduced sustaining capital requirements, while continued delineation of our existing land base can deepen our development inventory. These priorities position us to create lasting value from the assets we already own. The operating organization continues to execute safely and efficiently. I want to thank our field and office teams and our service partners for their focus and performance. With that, over to Chad Kalmakoff, to discuss the financial results and capital allocation.

Thanks, Kendall. Strong operating performance and commodity prices supported another solid financial quarter. We generated adjusted funds flow of $318 million or $0.48 per basic share. Free cash flow was $139 million or $0.20 per basic share after exploration and development expenditures of $186 million. During the quarter, we returned $165 million to shareholders. We repurchased 24 million common shares for $149 million and paid a quarterly dividend of $0.025 per share. Our balance sheet remains a significant strength and we exited the quarter with net cash of $522 million. This financial position supports the accelerated development Kendall outlined and provides resilience across commodity price cycles. Improved efficiencies and shorter cycle times have allowed us to accelerate the Duvernay, heavy oil and advanced enhanced oil recovery development. As a result, our 2026 exploration and development expenditures are now expected to be $665 million up from $625 million previously. Higher benchmark prices have also increased our royalty rate guidance to approximately 16%. Operating costs are now expected to be approximately $13.30 per BOE, improved from our previous guidance range of $13.75 to $14.25 per BOE. Transportation costs are expected to be approximately $3.75 per BOE, up from $3.40 to $3.60 per BOE previously. For 2027, we have initially allocated $150 million to share repurchases under the normal [indiscernible] bid with flexibility to adjust depending on market conditions. We expect to maintain the quarterly dividend at $0.25 per share. At a mid-cycle WTI price of USD 70 per barrel, we expect to maintain a net cash position through the 3-year plan. Sustaining capital is also expected to decline, reflecting our improved capital efficiency. That financial strength gives us the capacity to fund continued production growth, share repurchases and the base dividend, allowing us to keep growing value for our shareholders on a per share basis as we grow the business. With that, I'll turn the call back to Chad Lundberg.

Baytex is delivering on its strategy. Consistent execution is accelerating our growth plan while our discipline remains unchanged. What has changed is the pace, stronger operating performance, improved capital efficiency and lower costs give us the opportunity to accelerate development. We now expect the Duvernay to reach 25,000 BOE per day in the second half of 2028, 1.5 years earlier than our previous plan with the option to generate further growth or hold flat with an improved 15 years of inventory from that point. [indiscernible] continues to provide the foundation of the company with a deep inventory and enhanced oil recovery projects that extend the value of the resource. We are investing in high-return organic opportunities, advancing long-term projects in a measured way and continuing to return capital to shareholders. The result is a business that is growing faster and generating more free cash flow. We exceeded our 15% total shareholder return target in 2026 and and expect to achieve it again in 2027, while maintaining balance sheet strength to deliver through the cycle. I would like to thank our employees and service providers for their continued focus and safe execution. With that, we are ready for questions.

[Operator Instructions] The first question is comes from Menno Hulshof with TD Securities.

I'll start with [indiscernible] waterflood. It's a bigger question, but can you just remind us of what you need to see to scale up activity. And if you decide to move forward with commercial development, how quickly could that occur? And how would it fit into the 3-year plan? Or I guess the other option is that it displaces activity that is already in the plan. How are you thinking about that?

I think similar to messaging in the past, it takes time to understand waterflood performance. What are the key measures we're looking for is, one, just injectability check. We've got that. Two is we should see GOR suppression 3 as offsetting production response through decline as we type these wells out. I think we expect to see it by mid-2027. I mean we're going to see markers and tells ahead of that time. So it does take a little bit of time, but it's coming soon. Just in terms of the broader build-out, we are developing the acreage today, leaving gaps for future waterflood injectors. If we saw the tells and indicators that we are expecting to see we could layer in additional capital half through 2027. We think that would be in the $20 million to $30 million range. Again, that would be a first step to start backfilling some of the gaps we left with the injectors. So I don't know if that gives you a snapshot here after, but I think that's how we're thinking about it near term. Just in terms of longer term and how does it fit into the 3-year plan, if it works, we should start to see it pick up production performance inside the 3 years, how much is yet to be determined. I'll leave it at that.

Great. And then maybe just a second question on land acquisitions. How competitive was the process to secure the additional 15,000 acres in the Duvernay. And are you seeing opportunities to do more? Is it now fairly picked over? And then I guess on the other side of the ledger, what is the sort of the latest messaging on keeping versus monetizing the Viking?

Well, I think the simple answer is it's very competitive. I mean, look, what we're doing with the asset as we've held us since 2018, worked it through a delineation phase and just really learning and developing what we call this ecosystem of developing an unconventional improving the characterization, reducing capital costs, bringing the stakeholders along with us building out the infrastructure position to be able to handle these growth targets that we're ultimately achieving. And now here we are excited to step in the first year of full commercialization, hitting our production ramps 1.5 years early, seeing the reduction in capital costs to $930 a foot. It's ultimately flowing right through to top line breakeven reductions. I mean to say it's not competitive with what I just rattled off, I would be remiss. It's extremely competitive. It's great land. We hold a great position. And we're going to try for more of it. I think the message is sections, not townships from this point forward. It is largely held. On the Viking, it's a similar message. It's not core to the business at the right time, we would look to try to potentially monetize the asset the right time would be just how we think through the commodity cycle and acting contracyclically, which would point us into higher prices, ultimately triggering us into into potentially looking at it. Nothing further other than that, though, Menno.

The next question comes from Greg Pardy with RBC Capital Markets.

We got a huge land position one legacy stuff, Peace River Arch et cetera. Is there another Gemini in there somewhere?

We do have a large land position, 750,000 acres across basically the entirety of Central to Northern Alberta. I mean what's in the plan and we revealed a little bit more in our IR pack is 1,100 of what we call risk locations, we've expanded that to now include the full inventory set of 2,300 unrisked locations. So that -- those inventory wells are in the plan today. Second is we have the Gemini position, which sits on top of basically our Northeast Alberta acreage that you touched on. Do we have further to go in terms of modular SAGD properties inside that 750,000 acres. Look, it's what we're doing. It's what our heavy teams are scouring every day is just looking for opportunities, part of the exploration program is not only derisking and advancing that 1,100 risk well set to try and improve the 2,300 unrest, but it is looking for other opportunity within that set of land.

I don't think you want to answer my question.

Okay. Well, I tried to answer it by saying we have lots of opportunity without being specific about that.

Okay. Okay. No, no. That sounds good. And if I...

Let me just expand on that. We are always working up new initiatives and there are things we're working on today beyond [indiscernible], beyond what we've outlined in detail, beyond these primary well sets that we're just not talking about. They're not ready to talk about for various reasons, not technically far enough along the pathway could be competitive to Menno's question from a land sale perspective and tipping our hats further would put us in a compromised position strategically. So just -- so I hesitate to go further.

No, no, that's extremely good context. Okay, completely shifting gears and some of the recent Duvernay wells. I mean, a great rates, number one. Number 2 is the oil conde component very high in those. When you achieve the 25,000 BOE a day in 2028, what is the modeled product split between oil versus gas versus NGLs? And then just related to your capital program because the Duvernay is a big piece, have you factored in inflation distance into that outlook. And that's it for me.

So when these wells come on, they have a higher liquids component. So 65% oil, 25% liquids, 10% gas would be a general rule of thumb. And actually, if you look at path that was released in YoY in Q2 and then this one that we're talking about Q3 I think they're 87%, 88% liquids ultimately. So that's kind of where they come on. As we depressurize the reservoir, move through bubble point, we start to break out more gas in situ. And so that gets us to ultimately where we take these out at a 40% or 40% that grows 20% gas. In 2028, we would be -- as we model it out, basically right in the middle of that. So it's the mix of base that's maybe drifting a little bit lower and these new wells that are coming online that just have a little bit more pressure bottom hall. With respect to inflation, we have built, I would say, lower single digits into the plan. That's to account for what we're seeing on things like steel, things like diesel fuel. So we have built some into the plan. We have offset it to some extent, though, by all of the efficiency gains that we're talking about. We profiled the Duvernay efficiency gains, we've achieved some gains to our heavy oil program, as notably up in Peace River with motor size, whole size, style selection of how we're actually executing on the drill. So we think we've struck the right balance of honoring what we're seeing and kind of benching that against the efficiencies.

The next question comes from Amir Arif ATB Capital.

Congrats on a really good update here. The -- a couple of quick questions for you. Just on the operating cost improvement, I was surprised at how much you've been able to improve your operating cost structure? Is it more just driven by volume growth? Or is there other factors behind your operating cost improvement given the inflation that we're seeing in the industry?