Baytex Energy Corp. Aktie

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?

No debt volume growth is helping us as we put more barrels across 6 costs, we can amortize those fixed costs of and just a higher volume set that it is 1 of the benefits of growth Emer. Second, though, we would absolutely want to profile is just, I would call it the proactive nature of our operating teams as they rethink can challenge each other operating in all of the different areas.

So for example, instead of taking a piece of equipment to -- closer to failure or where it starts to break down at an increased frequency. We are really challenging can we put incremental costs into that equipment ahead of time. that ultimately, that's improved run life, but then also lower operating costs ultimately through the entirety of the lifespan of that piece of equipment. So that's one. that proactive nature. Two is just when we look at operating these wells, again, being proactive on how we're operating them. So with respect to maybe some of the lower producers, as an example where we would in the past, pump them at a 3 or 4 stopes per minute on a continual basis. We're electing to put them on a timer or even a pore timer where we shut them down for a week.

Turn them on for a day, produce the same amount of oil, but we greatly reduced the run time on that equipment and prevent it from wearing out further. So I think we're ultimately seeing it flow through in a much bigger way through our repair and maintenance line item in the OpEx expense part of the ledger twofold, pretty excited about what the teams are driving.

Got it. That's good color. And then just a second question. You've improved your corporate decline rate to about 30%. But under the 3-year outlook, if you start growing organically around 9%, where does your corporate decline sort of get to by 2029? What are your modeling or your plans?

I think this is one of the strengths of the 3-year plan. I'm glad you asked because it's a bit of a hidden gem traditionally a few were to go and grow an extensional position as we're talking about it, it does ultimately have a little bit higher decline than our corporate average. But when you balance it across the entirety of our portfolio in heavy oil by Duvernay, we actually see the decline modestly I'll say that we don't see the big improvements until we get into Clearwater waterflood or if we do get into an FID on our modular SAGD for half 2 '27, that would also materially improved phase decline. The point is though it doesn't go up, it ticks down moderately through the plan.

Even without the waterflood success?

Correct. So the Clearwater waterflood success. I would say, though, you do see in this plan that we are capitalizing more of our EOR projects throughout the Lloydminster region, in this particular instance, noted that we have 400 million barrels of oil in place resource that and projects ahead of us to go after. So that will start to pay and improve the decline through the base plan. And we've been capitalized -- that's not new. We've been capitalizing these projects for quite a while. I mean we've got 10% of our heavy oil production that is under flood influenced by most of that is polymer flood. This is a continuation of an investment in more of those great voor projects in the portfolio.

Okay. I appreciate that. And then just one final question, just a quick clarification on the Gemini SAGD you'll be in a position to potentially go to FID in second half '27. I'm assuming production would have come until under that time frame. But is the -- if you do, do an FID is the capital from that project included in the $800 million for '28 '29?

Yes. So our target is half 2 FID 2027. There are a couple more items that we're just trying to get our heads around to really come to that conclusion. So characterization, I think we've got a really good handle on it, capital costs. We've come a long ways on. I think by the end of the year, you'll see us have a design selection so size more of first phase that we would intend to execute on. We're still waiting on royalty framework notionally to be announced from the province and then some of the auxiliary items that we need to ultimately make a facility of this size go.

So water source, water disposal and then gas supply. So we're working through all those measures. We have 10 million dogs in the plan today for Gemini budget, $800 million total -- that is for further delineation of what we would call Phase III or pods 3 and 4 of the project. So 3D seismic over and then some stratigraphic test wells to just further define the steam chamber -- if we do reach FID half to 2027, there's another roughly that we would look to and think about adding to the plan in the back end of 2027. And then obviously, that would come with a step-up on the capital expenditures through 2028 as we point to first oil in 2029.

The next question comes from Sam Burwell with Jefferies.

This dovetails on the last one. Curious about how you think about and free cash flow in late '27 and then '28, assuming an FID of Gemini. Do you guys feel you have enough flexibility just with regard to the net cash position and the free cash flow you should be generating just curious if like there's flexibility in the plan to maybe scale down if commodity prices are lower or if WCS dips are wider or anything like that. Just curious how you're thinking about flexibility with Gemini potentially on the come.

I mean, we study this intensely as we think about capital allocation as we think about a fortified balance sheet that continues through the 3-year plan, as we sit today, we exit 2026. Again, we're in a bit of a choppy environment with respect to macro right now to say the least. But we do expect to exit the year at close to $400 million of net cash as we stress test the capital plan for 2027, $800 million with the commitment for $150 million to the buyback and it would still leave us ample capacity to handle capital expenditures on Gemini in the future and still leave us with that rock solid ironclad balance sheet.

Okay. Awesome. And then just a little bit more of a housekeeping question, but the incremental 2027 CapEx versus the prior plan, how does that break down or bucket between the Duvernay, Heavy oil and then anything earmarked for EOR Gemini?

So here's how we think about that. if you take $625 million, and that's kind of where we were yesterday before we released this press release. I'll just build you up to 800 from there. So there's an extra $90 million basically of Duvernay capital that's really stepping again into this first year, full commercialization, 21 wells onstream. It's basically an extra 3 drills and 8 completions -- the second is incremental heavy activity, so that's about $40 million to jump to that 130 well heavy oil pace from, call it, 110.

So an incremental 20 drills layering $35 million of EOR. So that's the Lloydminster polymer projects that we're excited about to the previous question, helping consider reduced base decline and that longer-term sustainability. And then last is $10 million going to Gemini, by way of 3D seismic and stratigraphic test wells, -- so I think that gets you to $800 million. That drives the 8% to 10% enhanced growth rate on an annualized basis and really important to flag 15% on a Q4-on-Q4 basis. First year step into Duvernay commercialization. You see the barrels come, they come later in the year. It is all, and that's what's driving that large Q4 on Q4 growth rate. So I guess we would look at this. We've got some shorter-cycle capital, Mid-Cape capital, so the EUR projects and some longer-term sustainability style capital by way of Gemini.

This concludes the question-and-answer session from the phone lines. I'd like to turn the conference back over to Chris Lessoway for any questions received online.

Have full of questions submitted through the webcast. So a question for Chad, Kay to start surround shareholder returns, maybe just reinforce our reinforce our plans for 2027 in terms of the dividend and the share buyback and whether there's flexibility or plans to adjust those amounts.

Sure. Thanks, Chris. So on the dividend to start plans to remain in the $0.09 per year dividend. No plans to increase that yet. I think generally, when we think about that, we want to further reduce the fixed cost or further reduce the breakeven. So it's sitting at $50 today. If we can increase that further, that there could be an opportunity on the dividend, but not today.

On the share buyback, we've initially set out at $150 million I just kind of outlined in the plans, we have an efficient capital program in hand for 2027. There are opportunities potentially within the plan to advance further projects that are very valuable to us, band waterflood, Gemini, et cetera. So maintain the flexibility around that buyback opportunity to adjust that Smart Basins. It was availability.

So initial $150 million, we will assess that as we kind of go through the year, kind of same conditions we always look at is kind of relative value, our intrinsic value and where we sit in the commodity side go along with kind of capital opportunities available to us.

This one is for Chad, see some news out there about the Caribou land sale that's forthcoming. Maybe you can just comment on any opportunities that we may see there.

Potential opportunity, no different than all of the other noncarb lens that we are actively pursuing, exploring, testing and ultimately, if we like the thesis are bidding on at lands. Caribou lands, I guess the only difference is it could stand to be a larger land sale. We don't know yet. We'll see in November here what the postings look like. It could -- it could be a little bit larger, and we're working off our plans to potentially be at the sale.

Thanks, Chad. Last question here for Todd Kay around hedging. Maybe just describe our philosophy around hedging in general and then in terms of WCS for next year.

Sure. Thanks, Chris. So we always kind of anchor our hedging program to our balance sheet. We obviously have a fairly fortified balance sheet to live through the voting cycles. So not looking to put on WTI hedges -- we do have WCS hedges here until the end of this year. Nothing on for 2027 at this point, obviously, in a pretty high differential environment today not looking to add anything at these prices if things be tightened, there could be an opportunity there on the WCS side.

Great. Thanks, Chad. So that's all the questions we have. So thanks again to everybody who joined the call today. For those of you who submitted questions we didn't get to, please reach out, and I will follow up directly. Thanks again for your time today, and have a great day.

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

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. Second Quarter 2026 Financial and Operating Results Conference Call.

[Operator Instructions]

The conference is being recorded.

[Operator Instructions]

I would now like to turn the conference over to Chris Lessoway, Vice President of Finance and Treasurer. Please go ahead.

Thank you, operator. Good morning, and welcome to Baytex's Second 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. 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. After our prepared remarks, we'll open the call for questions. Webcast participants can also submit questions online. With that, let me turn the call over to Chad.

Good morning. Q2 was another strong quarter. Production averaged 71,200 BOE per day, above the high end of our guidance for the second straight quarter with continued outperformance across our heavy oil portfolio and first well results from our southern land block in the Duvernay that we call Gilby. We repurchased 22 million shares for $139 million and exited the quarter with net cash of $566 million. With strong well performance to date, full year production guidance has been raised to 71,000 BOE per day, up 1,000 from the midpoint of prior guidance with a targeted exit rate of 72,000 BOE per day. There is no change to our capital program of $625 million.

Momentum is building with the renewed interest in Baytex as we continue executing our strategy. We have a clean balance sheet, deep inventory and a team executing with discipline. Our Q2 results reflect that. I am pleased to announce the appointment of 2 new directors: Derek Evans and Deanna Zumwalt. These appointments enhance an already strong board with depth in resource development and energy finance that is directly relevant to our strategy: growing production, capitalizing on opportunities in our portfolio and building towards our 15% total shareholder return target.

Thank you, Steve Reynish and Jeffrey Wojahn, for your significant contribution to Baytex. I'll now turn the call over to Kendall to walk us through operations, including our heavy oil and Duvernay results, the waterflood pilots and our second half program.

Thanks, Chad. Production of 71,243 BOE per day exceeded the high end of guidance, representing 11% growth relative to Q2 2025. We invested $122 million on exploration and development and brought 24.6 wells on stream consistent with our full year plan related to deliver strong production in the back half.

Heavy oil was strong across the board. At Peavine, 6 of the wells brought on stream during the quarter have established average IP30 rates of 478 barrels per day per well. Well results in Peavine continue to outperform internal expectations as development expands from the core.

At Lloydminster, 7 Mannville wells were brought on stream across multiple horizons. The stack keeps delivering at our multilateral and circulation string capabilities are a significant advantage here.

At Peace River, activity has picked up after spring breakup, and we are on track with second half development now underway. We have an active second half plan throughout our heavy oil portfolio with 4 rigs running and a fifth starting in Morinville, in August.

On waterfloods, both initial Peavine pilots are now on injection, one testing re-pressurization through producer-to-injector conversion, the other testing pressure maintenance on our new development. We are expanding waterflood pilots in the second half with 2 additional patterns at Peavine and Rex formation test in Morinville, both expected to be on injection by Q4.

At Utikuma, the 21 square mile seismic program is complete, covering roughly 20% of our 109-section land position. Initial interpretations confirm the presence of the Pekisko mounds and we are preparing for up to 2 exploration test wells in early 2027.

In the Duvernay, the first pad was drilled on our South Gilby acreage, which came on stream in June. Three of the 4 wells delivered average IP30 rates of 1,630 BOE per day per well with 88% liquids, amongst our strongest results in the Duvernay on a length normalized basis. The fourth well was completed at half lateral length after the bottom hole assembly become stuck during drilling and was unrecoverable. This well delivered an IP30 of 866 BOE per day. These results strengthen our confidence in the development opportunity across our Southern Duvernay acreage. The second Duvernay pad was drilled on our North Pembina acreage and completion operations are now well underway. This pad is expected to be brought on production in September.

The 2026 program is on track, 17 wells drilled, 13 on stream this year and the last 4-well pad to be completed and on stream in early 2027. Q2 was a safe and productive quarter. I want to recognize our operating teams, field and office. Their focus and disciplined execution drove our strong 2Q results. With that, over to Chad Kalmakoff, to discuss our financial performance.

Thanks, Kendall. Our strong operating results translate into strong finance performance. We generated adjusted fund flow of $254 million in the second quarter or $0.35 per share. Our operating netback was $55.33 per BOE, up from $35.36 per BOE in Q1, reflecting strong realized pricing and continued cost discipline. As a reminder, on an unhedged basis, every $5 move in WTI impacts our annualized adjusted funds flow by approximately $125 million. The hedges that were in place prior to the sale of our U.S. assets have rolled off as of Q2, and we no longer have WTI hedges in place. With a strong balance sheet, we don't anticipate entering into WTI hedges. We generated net income of $175 million in the quarter or $0.24 per share, bringing year-to-date net income to $108 million or $0.15 per share.

Free cash flow was $128 million or $0.18 per share compared to $2 million in Q1. The improvement reflects higher adjusted funds flow combined with investing $122 million on exploration and development. Holding annual capital flat while raising production guidance reflects strong operational performance and cost discipline.

During Q2, we repurchased 22 million shares for $136 million at an average price of $6.27 per share and declared a quarterly dividend of $0.0225 per share payable October 1.

Since the sale of our Eagle Ford business in December 2025, we repurchased 69 million shares, approximately 9% of the shares outstanding for $378 million. In July, our normal course issuer bid was renewed, providing capacity to repurchase up to 70.9 million shares through July 1, 2027. We continue to be active on the NCIB and anticipate repurchasing $650 million of shares from the proceeds of the U.S. disposition. Our balance sheet remains very strong, we exited the quarter with net cash of $566 million, which allows us to execute our plans and be resilient for all parts of the cycle. With that, I'll turn the call back over to Chad.

I want to close by putting in Q2 in the broader context of where we are headed. The strategy is straightforward: grow production 6% to 8% annually, capitalize on our heavy oil expertise, commercialize the Duvernay, drive the cost structure lower and return capital to shareholders. It's that simple. We are targeting a 15% annual total shareholder return at a mid-cycle price of $70 through production growth, dividends and buybacks.

That's the target we are building toward. The commodity price environment this quarter continued to prove constructive with WTI averaging $93 a barrel, and we maintain capital discipline throughout. The increased guidance reflects the quality of our inventory and strong execution from our teams. Heavy oil is the foundation over 12 years of risked drilling inventory, decades of multilateral and circulation expertise, active exploration and waterflood pilots at Peavine that could meaningfully improve long-term recovery.

The Duvernay continues to advance with the first pad now drilled on our southern acreage in Gilby. It confirms high-quality reservoir, strong well results and verifies inventory as we work towards running a full commercial program in 2027.

Gemini Thermal sits beyond the 3-year outlook, and we continue to advance our technical and commercial understanding, working towards an FID target H2 '27. Q2 was a strong quarter for Baytex as we executed our plans and advanced our strategy. I would like to thank our employees and service providers for their tremendous efforts to deliver these results.

And lastly, before we open for questions, I want to acknowledge Brian Ector. Today is Brian's last day at Baytex, closing out nearly 2 decades as the trusted voice of this company to the investment community. Brian has worked hard to set myself, Chris and our company up for success. On behalf of everyone at Baytex, thank you, Brian. It's been a privilege. With that, operator, we are ready for questions.

[Operator Instructions]

The first question today comes from Phillips Johnston with Capital One Securities.

Congrats, again, to Brian on his well-deserved retirement. My first question is for Chad Kalmakoff. You just affirmed, I guess, the target of $650 million of buybacks for this year in your prepared remarks. You're about halfway through, I think, at the end of June. If we look back at the monthly activity within the second quarter, it looks like there was some price sensitivity. It looks like you guys dialed back some activity in May when the share price was floating around $7 a share. So -- and I know at one point, you guys were considering an SIB to accelerate the buyback. So my question is, are you still -- I guess, my question is how opportunistic are you guys planning on being in terms of the share price in order to avoid procyclical buybacks?

Thanks, Phil. It's -- generally, we really just like the dollar cost averaging. So we do try to be reasonably steady where we can, we do feel like, so on a dollar per share -- sorry, a fixed dollar amount per day, kind of, naturally, dollar cost averages to the lower end, so you're buying more of the lower end and less at the higher end. And the $650 million, we're kind of -- that's about $2.5 million a day. We probably find it to be fairly steady with that for the back half of the year.

Okay. And have you ruled out an SIB at this point?

Yes. In fact, yes, we basically ruled out an SIB today. I think we can meet this commitment through the NCIB. We like the NCIB approach. It's tax-efficient, it's dollar-cost-average efficient and it's not trying to time to market.

Okay. Perfect. And then maybe a second question for Kendall. Nice to see the strong results on the 3 Gilby wells. I wanted to ask if those results, sort of, alter your development strategy for the southern acreage going forward? And do you think the results imply some upside to your inventory assumptions? Or is the success there sort of already baked into what you've laid out?

Yes. I mean I think -- thanks for the question. I think it's early time, but obviously, I think this confirms our expectations for the acreage. In terms of upside at this point in time, too early to say or comment further.

Yes. I think, Phil, like, IP30s are great, and these wells at 1,630 BOE per day, 90% liquids essentially were great results. Some of it was a result of flowing through surface facilities and capacity. And then the second was just a little bit on performance. And really, the question now is where do these now trend to -- with respect to curve. They're slightly beating right now, but we just need more time to analyze. No change to plans.

The next question comes from Amir Arif with ATB Capital.

Congrats on the quarter. Just a follow-up question on the Duvernay. The results were very strong. I was just curious, did you do anything different on the completion approach out here? Or do you think it's more just a reflection of that Southern acreage in terms of the oil cuts and the higher rates?

Thanks, Amir. It's Chad L, I guess. This is a continuation of a long journey in the Duvernay. And so we are continuing to try new things. I think last year, as I spoke before, was all about near wellbore uniformity. This year, we're really looking to far field. So as we move the sand and commodity further from the wellbore, can we still build that efficient frac pack to drain the reservoir? So there's some nuances with respect to the cluster and perf design. We have also been testing different tonnages and water loadings, and you can expect to see more of that through our program this year. In terms of Gilby itself, we did test a higher tonnage loading specifically. But as of right now, it is just pad results, it's rock results, and it's going to take time, as we just spoke, to really understand what's happening in the nuances with the completion program.

That's helpful color. And then just a second question more on the Peavine injection pilots that you have on the first quarter on injection. I was just curious, what different pattern design are you planning to test with the 2 additional pilots that you're planning to do out there?

So the 2 additional pilots are new injectors in combination with new drills. So injection on stream same time as production. So that differs from 1 of the 2 original pilots. The first pilot is injection into our original discovery well two-leg lateral where that will be all about fill up, how fast can we fill up the injector. That was a producer and then start to see a response on the producers. These expanded patterns are just to gain an understanding of: a, slightly different rock, so to continue to develop our statistical average of what this looks like; and then second, to observe what happens when we inject at the same time and start first production.

Okay. So similar to one of your existing injections, but it's a different pattern, a different layout or just different rates that you're planning to set?

So very, very similar to the second pilot, where it's new injectors, new producers, just different pad. This pad further to the West, so slightly different rock.

Got it. Okay. That's helpful. And then on the Pekisko mound opportunity set. I know you've run the seismic. Just curious when you'll be starting to drill any of those prospects that might be on your lands?

You bet, it's Kendall here. Currently, we're just getting ready for permitting ready for would be Q1 2027 test wells going in.

Okay. And then would you know what the average cost would be on one of those tests for the Pekisko?

Yes. Sorry, about $2.5 million per well.

$2.5 million, okay. Sounds good. And then just a final question, just more on the hedging thoughts as you've let the hedges roll off. I know you've got a clean balance sheet, no need to add hedges. But historically, you have put in wider collars to at least provide a floor for your CapEx level spend. Any thoughts in terms of going forward, are you just planning to keep it completely unhedged or are you still thinking about maybe having some wider collars out there for some downside protection?

Thanks, Amir. I think, actually, now, we're -- with the balance sheet -- even before, I think we always kind of linked to hedging to the balance sheet. Where the balance sheet is at today, we're not looking to do any more WTI hedges, so we'll just let it flow with the commodity.

The next question comes from Dennis Fong with CIBC WM.

Congrats on the strong quarter and again as well as Brian Ector. My first one is maybe kind of continue to focus on the Duvernay. You've obviously seen cost efficiencies as you continue to evolve kind of the way that you're developing it. Are you seeing anything further as you kind of move to a little bit more of a commercial style development and maybe ramp up the level of activity as well? And can you talk toward some of the, kind of, further innovations or maybe we'll call it, tweaks to your development model as to how you think about completion design and so forth as you evolve through the play?

Sure. Thanks, Dennis. Just as a reminder, in 2024, we were about $1,150 per foot total DCE costs. Last year, 2025, $1,050 per foot. This year, we're budgeting $1,000, and our target is $900. That has been a steady improvement on efficiency through the process. We're continuing to see efficiencies. We expect to have a full cost, kind of, recs come out in Q3 as we're only on the second pad. We're just currently fracking second pad right now.

What I can say is on the drilling rig we are starting to see further efficiency going to the 17 wells per year now that we've committed to drill for 2026 and then some on the completion rigs. To be very, very specific, some of the work we're doing with cluster designs that I talked about previous, not only will help with respect to potential performance increase, but could help on the cost efficiency side, i.e., if we can put commodity in the ground at a more efficient way.

Maybe we can put less in to garner the same results. We have gone to trials on wellbore gas, where we're actually using gas right at site to power the frac equipment. That's been pretty exciting. And then just some of the work we're doing with mud systems, centrifuges, further processing of the muds at surface drilling muds, I should say, before they go back into the well to drill with or helping to improve costs on the drill side.

Maybe just the last on infrastructure. So we have complete in Q2, our second of 5 main water reservoirs. That will also help just with respect to the amount of lay-flat we have to lay to ultimately frac the wells. So there's -- it's a variety of fronts, kind of all fronts, not just drilling that we're really working on.

Great. I appreciate that color. Switching over to Gemini. I appreciate your comments about moving towards a decision later in 2027. Can you talk towards what there is left in terms of work to do to feel comfortable moving forward with an FID on Gemini and kind of how to think about the items that you're balancing going into a potential sanctioning of that project?

Yes. So there's 3 main things. I'd start with this. We've continued to add to our Gemini team. So we had a skeleton crew coming in left over at Baytex, and we've now got 3 incremental team members, great hires that we're really excited about advancing it forward. So the engine is running full steam ahead.

There's 3 things that we're reacquainting with: First, on the subsurface characterization, furthering our understanding of the rock models and deliverability. Second is on the surface facilities. So there's been a lot of work done in the last decade with respect to small scale modular SAGD operations, a lot of advancements technologically. So we're just getting our hands around that and around ultimately the capital costs.

And then the third is just regulatory. So obviously, regulatory has been a big part of our world for the last decade. There is significant optimism and it looks like it could be movement to help incentivize new growth in the province to fill this notional 3 million barrels of incremental capacity and egress out. And so really just getting and putting a pin in the regulatory framework and how that intersects with the other two items that we're looking at.

This concludes the question-and-answer session from the phone lines. I'd like to turn the conference back over to Chris Lessoway for any questions received online.

Several questions here. I'll start with one for Chad K. Obviously, some cash on the balance sheet here in Q2. Maybe talk a little bit about how that cash is invested and what kind of rate we're earning on the cash?

Sure. Thanks, Chris. So we do keep cash within the Canadian chartered banks within our syndicate, generally keep it liquid just in savings accounts. In short, to be having quick access all the time. So we're generally getting around 2.75% on cash investment.

Great. Thanks, Chad. I'm going to follow this up with a question on debt as well. So a small portion of the USD bonds remain outstanding currently. Maybe talk about plans for those going forward and how we intend to fund the repayment of those.

So yes, obviously, still kind of the stub bonds left over from the Eagle Ford disposition. They're fine with the capital structure for now. I think the first call on those bonds would come next March, opportunity to take them out if we felt that was the right idea. We have cash on hand to do that. We wouldn't be looking to do anything with other funding alternatives to kind of take those out because we'd fund it with cash on hand.

Perfect. Thanks, Chad. A couple of questions here on the waterflood. I'll point these to Kendall. Maybe a couple of comments on milestones we're working towards on the pilots, what are you looking to see? And then a second question here, where is the waterflood -- sorry, where is the water coming from and just talk about availability as we expand those pilots?

Yes, sure, Chris. First, just on the water and where it's coming from, that's just produced water from the field currently. So we have sufficient water volumes produced for the pilots that we're undertaking right now. Subsequently, into -- if we were to move into commercial operations with drilling dedicated. Source wells could be similar, but different formation [indiscernible] but no expectations on challenges there. With respect to what we're looking to see probably in that 12- to 18-month time frame, depending on injectivity, starting to see response deviation from primary base decline rates and also GORs becoming suppressed in that time horizon.

And probably just -- I would just add that the very first just on the injectivity front. That's something that we're going to have a handle on right away. So several markers.

Last question here, I'll put this back to Chad K. Remain listed on the New York Stock Exchange. Maybe talk about that going forward.

Yes. We're obviously on the NYSE, no plans to change that at all. So I think there's -- we can expect to be trading on the NYSE for the foreseeable future.

Perfect. So I think that wraps everything up for today. Thanks, everyone, for joining our call. For those of you who submitted webcast questions that we did not get to, please reach out to our Investor Relations team, and we'll follow up directly. Thanks, again, for your time today, and have a great day.

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

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. First Quarter 2026 Financial and Operating Results Conference Call. [Operator Instructions] The conference is being recorded. [Operator Instructions]

I would now like to turn the conference over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

Thanks, Dave. Good morning, and welcome to Baytex's First 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. This is Chad's first call as CEO and Kendall's first as COO.

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. After our prepared remarks, we'll open the call for questions. Webcast participants can also submit questions online.

With that, let me turn the call over to Chad.

Well, good morning, everyone. Q1 was a strong start to the year. Production averaged above the high end of our guidance at 69,500 BOE per day, driven by outperformance across our heavy oil portfolio. We exited the quarter with net cash of $591 million and repurchased 35 million shares or 4.6% of our shares outstanding for $174 million. With this outperformance and a constructive commodity backdrop, we are raising our 2026 production guidance to 69,000 to 71,000 BOE per day. This represents 7% annual growth at midpoint, up from 3% to 5% previously.

We are maintaining discipline with capital expenditures moving to the high end of our guidance, $625 million and includes incremental projects in our Duvernay and heavy oil. Along with updating our current year guidance, we are also updating our 3-year outlook. With the depth and quality of our inventory, we are targeting 6% to 8% annual production growth through 2028, up from the prior midpoint of 4%, while maintaining a net cash position throughout the period.

Before I turn the call over to Kendall, I want to acknowledge two appointments that were announced yesterday. Kendall Arthur moves into the Chief Operating Officer role, and Adrian Blazevic has been appointed Vice President, Heavy Oil. I have worked closely with both for the past 8 years. They have been instrumental in building our Canadian operations and are central to our long-term leadership plan. I am confident in their ability to execute and deliver against the strategy you will hear about this morning.

Kendall, over to you.

Thanks, Chad, and good morning. We had a strong operational quarter. As Chad mentioned, production of 69,500 BOE per day exceeded the high end of our guidance, with oil and NGL representing 88% of the mix. We invested $145 million in exploration and development and brought 53 wells on stream, consistent with our full year plan. In heavy oil, we delivered strong results across the portfolio. At Peavine, the first 6 wells of our 2026 program averaged 30-day IP rates of 680 barrels per day, well above the expected type curve. At Lloydminster, we stepped up to 3 rigs during the quarter, successfully targeting 7 discrete horizons across the Mannville stack, bringing 16.7 net wells on stream. At Peace River, we brought 3 wells on stream and acquired an additional 40 sections at Utikuma, bringing our total land position to 109 sections.

We completed a 21-square-mile seismic shot covering approximately 20% of the land base and following interpretation could drill our first exploration test well in early 2027. In the Duvernay, we drilled our first 4 wells of the year with completions now underway. First wells are expected on stream in June, with the 9 following in Q3 and Q4, totaling 13 wells on stream in 2026 and with 1 4-well pad drilled and to be completed in early 2027. It was a safe and efficient quarter, and I want to recognize our field teams for their dedication and hard work.

With that, I will turn it over to Chad Kalmakoff.

Thanks, Kendall. This marked our first full quarter of results for our Canadian business. We generated $152 million of adjusted funds flow or $0.20 per basic share, and our operating netback improved to $35.36 per BOE, up from $29.30 per BOE in Q4 '25, driven by higher realized pricing and continued cost discipline. We realized hedging losses of $29 million in the quarter. Our exposure to the current strip will increase as our WTI hedges roll off at the end of Q2. As a reminder, on an unhedged basis, every $5 move in WTI impacts our adjusted funds flow on an annual basis by approximately $125 million.

We ended Q1 with a net cash position of $591 million. And as Chad highlighted, we repurchased 35 million shares or 4.6% of the shares outstanding for $174 million. The balance sheet is in excellent shape with full flexibility to fund our capital program and return capital to shareholders. Our quarterly dividend of $0.0225 per share remains unchanged.

With that, I'll turn the call back to Chad.

Thanks, Kendall and Chad. I want to close by stepping back from the quarter and speak about the business and opportunity in front of us. Our strategy is straightforward: grow 6% to 8% annually, advance the Duvernay and our heavy oil portfolio, invest in future optionality and return value to shareholders. We are targeting 15% annual total shareholder return at a mid-cycle price of $70. This is through a combination of production growth, dividends and share buybacks.

We can deliver this with the strength and depth of our current portfolio. The Duvernay is on track to deliver 35% production growth in 2026, with an exit rate of 14,000 to 15,000 BOE per day. Our heavy oil assets carry 12 years of drilling inventory at our current pace, with the active exploration across the fairway and two Peavine waterflood pilots underway.

We are also driving our cost structure lower, the long-term sustaining breakeven target is under $50, further enhancing our resilience through the cycle. Gemini thermal represents significant long-term optionality that sits beyond our 3-year outlook. Gemini is a regulatory approved project with 44 million barrels of booked reserves and a first phase design of 5,000 barrels per day. We are advancing our technical and commercial outlook toward a final investment decision in 2027. This is a business with deep, profitable heavy oil inventory, a growing Duvernay and net cash on the balance sheet, we are excited to show what Baytex is capable of.

Before we open for questions, I want to recognize two people. First, Eric Greager. Through his leadership, Eric helped to establish the disciplined Canadian platform we are today. He has worked to ensure a seamless leadership transition and has positioned the company for success going forward. Second, Brian Ector, I did not want to let this call pass without saying Brian has been the trusted and steady voice of Baytex to the investment community for many years. He will be retiring at the end of July, and we look forward to working with him through the transition. On behalf of everyone at Baytex, thank you both. It has been a pleasure working with you.

With that, we are ready for questions.

[Operator Instructions] Our first question comes from Phillips Johnston with Capital One.

I wanted to ask about the new 15% total shareholder return target, which is rather impressive. I just want to make sure I'm thinking about it correctly. So if we assume the new 3-year growth rate is around 7% and you add the 1.5% base dividend yield to that, you need another 6% or so from share buybacks to bridge that gap, which in round numbers, I think it's around $300 million of share buybacks per year.

So my question is, is that math correct? And I guess, as a follow-up, I realize that this year's buyback is going to be significantly north of that figure. So conceptually, should we think about the buyback in '27 and '28 as being significantly lower so that you average around $300 million per year over the 3 years? Or is that a decent placeholder for '27 and '28?

Okay. Thanks, Phil. Appreciate the question. I think this one is very important to be clear on. So yes, at a top line, first priority is to deliver a 15% return to shareholders. As you said, that's inclusive of production growth plus a dividend plus our buyback program. If we just step back, I just want to reiterate the commitment from the proceeds from the Eagle Ford sale. So 75% or $650 million will be deployed in 2026 through the buyback program. Beyond that, though, we think this business is capable of and are targeting the 15% that you described as we think about moving from this point into the future.

Okay. Great. That clears it up. And then I wanted to ask you about the incremental CapEx spend for the year. Does that increase factor in any service cost inflation? Or is it just a reflection of the increased activity?

So maybe just a little bit of minor cost inflation, we're seeing no doubt on the diesel side right now. I don't think you could say we have it all baked into this point in time. Short of that, no. That is something that we're thinking about. We've got, though, most of our service supply costs locked in for the year for calendar 2026, certainly. And so we'll just have to see. We're 70 days into the war, 70 days into a complete flip on a macro basis with respect to supply/demand and the oil market. Just continue to monitor and see where supply costs go.

And the next question comes from Greg Pardy with RBC.

Congratulations to everyone. And then Brian, it's been just amazing working with you for such a long time. So all the very, very best.

Chad, I wanted to ask you just a little bit about Gemini. And I know in your opening remarks, you did frame it and indicated that it would be beyond the 3-year plan as you look at it. What are the next steps in terms of how you're approaching this? So for example, I know it's been framed at 5,000 barrels a day or so at this point, is that a number conceivably that could go up? And then just what about the team perhaps that you're assembling within the -- are you assembling a team within the organization just with depth of expertise in thermal?

Okay. Thanks for joining, Greg. Yes. So let me start high level. Gemini has been in the portfolio since 2014. We've identified 300 million barrels of resource on the project at a modest 50% recovery that would put us at 150 million barrels that we're targeting to capture. As I said in my comments, we have regulatory approval for Phase 1 of the project to develop it out. What does that mean? It means we have 3D seismic shot. We have vertical stratigraphic test wells to identify and confirm the chamber. And ultimately, that gave confidence for the approval. So that would be Phase 1.

If you do the math on the total resource that's available to recover against 5,000 barrels a day, it would put us out at a 75-year ROI. And so that would make us think about incremental projects to enhance the production beyond the 5,000. Can we get to 10,000 or maybe a little bit above? I think there's a chance. What do we have to do? So a bit of the team has been scheduled since the initial projects back in 2014. We had a recent hire as some picked up on the web into the thermal team that we're very excited about, relooking at the commercial, technical, capital cost, outlook on the project. And from there, we're thinking about trying to get to first FID or an FID decision in early 2027. That means we ultimately have a chance to put first barrels online in 2029.

Does that help, Greg?

Chad, it helps a lot. It helps a lot. You know how I feel about thermal. So that's music to my ears.

Maybe just back on the conventional side, as you look at your 3-year plan now with a higher growth rate, I mean, typically, with that comes higher decline rates, higher natural declines and then also higher sustaining. Could you maybe just -- again, I'm hating to use this word frame over and over again, but could you maybe just put some context around how your decline curve is going to shift? And then maybe what sustaining looks like over the next maybe 2 or 3 years, just in broad strokes?

Sure. So as you pointed out, 6% to 8% production top line growth over the 3-year plan. The bulk of that comes out of the Duvernay asset, but there also is some coming from heavy oil. Heavy oil is 75% of our production flows today. And I would remind everybody that of the 75%, approximately 10% of our heavy oil is waterflood derived at this point in time. So if you look across that piece and portion of our portfolio, we have very competitive declines in the space.

As we think about that 3-year plan, our decline stays actually relatively flat with the growth. On top of that, though, we have the incremental projects and catalysts that don't sit inside the 3-year plan today. So Peavine and waterfloods that are being piloted right now. We have incremental project opportunity just across the conventional cold flow heavy oil fairway as well as just working on the cash cost structure and making the business better, which we do as meat and potatoes every day inside the company.

And the next question comes from Menno Hulshof with TD Cowen.

Congratulations, Eric and Brian. Just maybe I'll start with a question on the balance sheet. You talked about running net cash under the 3-year plan, which is great to hear. But can you maybe describe your philosophy in a little more detail? And is there a scenario where you would take on a bit of balance sheet leverage? I'm assuming the answer is no, but maybe you could just walk us through that.

Yes. Menno, I guess, first and foremost, we think that a strong balance sheet is paramount for oil and gas company and the cyclical nature of the commodity. So that would be step one. We view debt as a potential tool in the event we need it. We would not look to ever use it as a tool to go into debt like we were certainly in the past before the Eagle Ford transaction and the repositioning that we've undertaken. As you think about this company going forward, if we did elect to use kind of half a turn at that $70 or mid-cycle pricing would be a threshold boundary that we wouldn't exceed and there would have to be a very good reason to take it on.

Great. Chad, and then the second question is on the outlook for 2027. And I understand we'll have to wait for the release of 2027 guidance for the full details, which is still a long way out. But what ultimately drives the decision to grow 6% next year versus 8% and oil price, of course, is going to factor in. But what are the other sort of considerations in sort of getting from 6% to 8% or the other way around? And then what are the broad strokes in terms of growth spending and activity levels based on what you're seeing today?

I think it comes back to what we're really trying to do with a company, and that's just drive value out to the shareholders, reposition inside Canada with these great assets that we have. When you think about how we do our capital planning, it's really a bottoms-up buildup from the teams. The question we ask is what is the best way to run this asset. And so what does best mean? So where can you deliver the strongest returns, strongest capital efficiencies to ultimately drive this growth. The fallout is the corporate top line production. And so when we talk about 6% to 8% in '27, '28 and beyond, this moves us, for example, to an 18- to 20-well program in the Duvernay. Again, that is where we hit a 1-rig levelized pace, and we have a shot at improving our capital cost structure even further than what we've demonstrated to this point in the asset.

Equally so in heavy oil, where we would look to run the 4 rigs essentially that we keep going around the clock with the rigs to build on the crews, the teams and efficiencies within. So I think that's what underpins the growth, Menno, is just coming at it from a point of view of where can we drive the maximum value and returns to the shareholders. If you look at 2027 with what I just said and think about capital costs, this year, in the press release yesterday, we're going to 13 rigs drilled complete, tied in and online in the Duvernay, an incremental pad in the Duvernay that's ducked into 2027, and next year, 18 to 20 wells. That's going to come with some incremental capital, and you can expect that to be additive to the $625 million where we sit today. Does that help, Menno?

Yes, that does. That's great.

And the next question comes from Dennis Fong with CIBC.

First, congrats also to Brian as well as Eric. My first one maybe falls a little bit further along the line from what Menno was asking there was you've obviously showcased very strong well cost improvement in the Pembina Duvernay. Again, as you switch towards kind of a 1-rig development program and start to kind of roll in a lot of those efficiencies, what do you think cost structure can get towards with respect to cost for -- within the Pembina Duvernay?

I'm going to answer that very directly. So if you look in our slide pack on Page 10, we outlined what we've been doing with Duvernay costs. So in 2024, we moved from $1,165 per foot to 2025, $1,050 per foot of lateral length completed. We're budgeted out this year at $1,000 per foot. And we think, and this is the power of getting to scale in the assets is that at full rig activity pace, we have a shot at getting to $900 a foot or better.

I think that directly answers your question. The broader question of that is just the ecosystem of unconventional development. I think people really have to understand what we've done at this company. We talked about costs. We haven't talked about characterization, again, Slide 10 points to what we've done kind of year-over-year, '24 to '25 on the characterization front, moving from 80 BOE per foot to 90 BOE per foot. We haven't talked really about facilities and water infrastructure, but that's part of the ecosystem that needs to be developed to really optimize and maximize your efficiencies. This year, we do have a little bit of incremental facility spending, for example, as we built our budget, it's about $50 million with the majority of that going to the Duvernay. We have 3 years of elevated facilities spend in the Duvernay, so '26, '27 and '28, at that $35 million range. After that, it drops to $10 million going forward. That gets us 5 of 7 major anchor batteries completed. That gets us 2.5 of 5 of the water reservoirs completed.

I think just the last point I'd make is the stakeholder relations. We have an absolutely tremendous surface stakeholder team at the company and the amount of work they've done to complete the formula for how you're successful in unconventionals is -- has been very strong. So Dennis, I tried to answer it very direct, but then broaden the question because there's many things that need to be taken into consideration.

I really appreciate that. The incremental color. And yes, it will be nice to kind of see where the cost structure trends to, especially as you move to a more scalable development.

My next question turns towards the waterflood over at Peavine. I know you're initiating the 2 pilots with 2 different styles of, we'll call it, waterflooding technique. Can you maybe talk towards some of the data points or key metrics that you're looking for or hoping to find in terms of each of those pilots? And how that may kind of provide you insight to its possible deployment across your existing field and kind of the future development of the play?

I can. So waterflood at Peavine, we're currently drilling and converting our two pilots. So one of the pilots is a conversion of a 2-leg lateral. It was actually the initial discovery well in the play to an injector. What we will be actively trying to observe on that pilot is how fast can we fill up the voidage or oil that we've pulled out of the ground already? And what happens when we get that voidage refilled with the offsetting declines and subsequent production on the active producers.

The second pilot is where we're drilling new producers in conjunction with new injectors. Again, as we turn the production online, we will immediately turn injection online, and we will be trying to and attempting to observe what happens with decline. And ultimately, what that does in all of this to the recovery factors on the wells up in the Peavine.

Maybe if I just step back a little bit, we do hold 48 of the top 50 wells on primary production in the Peavine, and you can see continued strong results with the delivery of primary development in Q1. And I think that as you think about waterflood in general and conventional cold flow heavy oil, just in broad brush strokes, typically, you get to a 7% recovery on primary development, double that with waterflood, again, very broad brush, so 15% and then push to greater than 20% as you go to more of a polymer flood style development techniques. In some of our primary wells, we've surpassed and gone as high as a 15% recovery. So seeing tremendous recovery from, again, the primary production.

So just boiling it down, Dennis, we're looking for base decline on offsetting wells. We're looking at how that translates into ultimate recovery factor. And then we're looking for how that ultimately flows straight through to top line production out of the asset. But we're pretty excited about what it does for the company if it works.

Great. Great. And if you'll permit me one last question here. I'm looking at Slide 12 within your presentation. And what you've kind of highlighted there is an opportunity set targeting 8 discrete development horizons within, we'll call it, the heavy oil exposure that you guys have. I see that most of it is coming effectively from the Waseca and the Sparky. Can you maybe characterize the opportunity set that exists from targeting the multitude or the full stack of formations or targets here as you go forward, both from an inventory perspective and even a growth perspective?

We're very excited about this area. So up in Northeast Alberta, we've doubled the land position in the last 5 years, but we've also opened up the 8 different stacks to the layer. So we think about it as a cube of oil in place. You're right, the initial production is from the Sparky formation. And quite frankly, that's what we identified on a map 5 years ago in our long-range planning. That's what I would have said we are chasing in this area.

With the work that's been done by our technical teams and then industry broadly, mapping out the signatures of the Clearwater rock, it's really opened up the incremental opportunity set here to the Waseca, as you pointed out, the Colony, McLaren and the various different zones that sit within that stack.

I think here's the opportunity. Right now of the 1,100 wells that we hold that we call a risk inventory set in heavy oil, approximately half of them sit on this Northeast Alberta property. There is further incremental inventory that we're actively derisking by way of some of the exploration dollars drilling stratigraphic test wells and/or just committing to an outright development style well. They are $2 million wells. And so at times, we'll just push right through to drilling the well.

So I think the opportunity is large. As I said, it's a cube of oil in place, over 8 different layers and a map sheet that's greater than 100 sections. There's two predominant zones that we're producing from right now, but you can see that we're starting to uptick the different layers as we move further out in time. And so look for us to continue to advance and unlock that in the future and in future updates.

This concludes our question-and-answer session from the phone lines. I'd like to turn the conference back over to Brian Ector for any questions received online.

All right. Thanks, Dave. We do have several questions coming in from the webcast. So I'll try to summarize a few of them here. But first, to Chad Kalmakoff, can you maybe, Chad, elaborate on our hedge -- maybe the hedge book and our hedge philosophy going forward?

Sure. I'll hit the hedge book first. We still have about 50% of our WTI hedged until the end of Q2. Those have been legacy hedges that we had in place prior to sale of the Eagle Ford. So as I mentioned in the introductory remarks, once those roll off, we have pretty robust exposure to WTI prices.

In terms of philosophy going forward, I think we've always had a strong balance sheet, best hedge. We wouldn't be looking to hedge any more WTI exposure. And obviously, with our cash position we're in enviable spot. So not looking to do any more WTI hedges. We continue to hedge differentials in WCS, MSW. We're about 50% -- or sorry, about 40% hedged, 43% hedged on WCS for the remainder of the year, around 13%. That's something that will probably continue on in the future to kind of hedge those differentials.

And the question, I know like we discussed the shareholder return framework with a couple of analyst questions. A number of questions coming in, just around dividend philosophy, and just the shareholder return again, Chad, can you just maybe elaborate on the thoughts around the dividend versus the buyback program.

Yes. So at a top line, we talked about the target to deliver 15% returns to our shareholders at $70 oil comprised of growth plus dividend plus buybacks. We talked about $650 million coming to shareholders this year by way of buyback. The other 25% of the proceeds, I would remind everybody is being deployed to small incremental greenfield tuck-in and bolt-on sale activity that we would like to think we're very, very good at to enhance and/or extend our current inventory position.

With respect to the dividend, Brian, specifically, we pay $0.09 a share today that depending on where our price is in the 1.5% range as part of the formula. We do not intend to increase the dividend at this point in time. That would be something we might look at in the future. But as we sit today, everything is evaluated on our best returning risk-adjusted basis. And this is the formula that we're moving forward with.

One last question around the free cash flow generation of our business. We were a couple of million dollars in Q1, Chad. And just a thought on expectations as the year unfolds for free cash flow.

Sure. I think we expect the balance of the year to be more robust. We kind of touched on the hedges, so that kind of impacts Q2 a little bit. But beyond that, if you think about an $80 average price for the remainder of the year, that would put you into the around $250 million of free cash flow for the balance -- for 2026 in total. And then again, you can think about the WTI beyond that, the $125 million, we want $5 on a full year basis, that would be kind of your notional changes.

Perfect. Thank you. So free cash flow will grow as the year unfolds. That was kind of the questions coming in from the webcast. That does wrap up today's call and the questions that were coming in. We'd like to thank everyone for joining us. Thanks again for your time, 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.

Good afternoon. Thank you for joining us today. My name is James Maclean, and I am the General Counsel for Baytex Energy.

Before we begin, I would like to provide a quick overview of the Lumi virtual meeting platform. You should now see the agenda on the left side of your screen. At the top of the agenda page is a legend showing four different icons you may click on to access different parts of the platform. For example, to ask a question, click the comment bubble icon for written questions or request to speak button to ask a verbal question. The voting icon will only be displayed once the polls are open. Note that if you are attending the meeting as a guest, you will not have the ability to ask questions or vote. Thank you.

And I will now turn it over to the Chair of our Board, Mr. Mark Bly.

Good afternoon, everyone. Welcome to the Annual Meeting of Shareholders of Baytex Energy. The meeting will now come to order. I am Mark Bly, the Chair of the Board of Directors of Baytex, and I'll act as Chair of the meeting.

As we are holding this meeting virtually, during the meeting, registered shareholders and duly appointed proxy holders who have logged into the meeting using their control numbers provided by Odyssey Trust will be able to ask questions. There are two ways for shareholders and proxy holders to ask questions using the chat function for written questions or verbally using the device that you have used to join the meeting. To ask a written question, select the messaging tab, type your message within the box at the top of the screen and click the send arrow. As it relates to live audio questions, click the request to speak button in your broadcast window. Please enter your full name and the topic of your question. If prompted, click allow in a pop-up to grant access your microphone, click join the queue to confirm that you are ready to join the live audio facility, and once in the queue, you'll be able to listen to the Q&A session.

When it is your turn to speak, the moderator will ask you to please ask your question. You will hear a beep, after the beep, please go ahead with your question. Please refer to the virtual meeting guide posted on the documents page of the meeting platform.

I shall ask James Maclean to act as Secretary of the meeting; and Jackie Fisher, representative of Odyssey Trust Company, to act as scrutineer.

I've now received an affidavit from Odyssey Trust Company that the notice of the meeting, the information circular and the forms of proxy have been mailed to the shareholders of Baytex in the proper manner. I direct that the affidavit, together with copies of the documents mailed to the shareholders, be kept by the secretary with the minutes of the meeting. With the consent of the meeting, the reading of the notice of meeting will be dispensed with.

Business may be transacted at this meeting if two or more persons are present, holding or representing by proxy not less than 25% of the shares entitled to vote at the meeting.

The scrutineers' report has now been received, and it shows that there is a quorum of shareholders present at the meeting. I direct that the scrutineers' report on all matters be annexed to the minutes of this meeting as a schedule. I now declare that the meeting is regularly called and properly constituted for the transaction of business.

We will conduct each vote by way of vote cast on the Lumi platform and those submitted by proxy. I understand that the scrutineers have tabulated all of the votes received prior to the voting cutoff. If you have previously voted, you do not need to vote again. By voting again, you will revoke any previous vote made prior to the voting cutoff.

We will now open the voting for all of the resolutions. Voting results may be obtained from the secretary after the meeting. I would first like to present the financial statements for the year ended December 31, 2025. These are located on the Lumi dashboard page and are available electronically on Baytex's website.

The next item of business is the election of directors. In accordance with Baytex's advanced notice bylaw, the individuals nominated for election as directors at this meeting are the persons named as nominees in Baytex's information circular and proxy statement dated March 20, 2026. They are Mark Bly, Trudy Curran, Chad Lundberg, Don Hrap, Jennifer Macy, David Pierce, Steve Reynish and Jeffrey Wojahn. I would just remind everyone that voting is open for all resolutions.

The next item of business is the appointment of auditors.

I, Chad Kalmakoff, move that KPMG LLP be appointed auditors of Baytex until the next annual meeting or until their successor is appointed and that their remuneration as such be fixed by the Board of Directors.

I, James Maclean, second the motion.

The next item of business is the advisory vote on executive compensation.

I, Chad Kalmakoff, move that the nonbinding advisory resolution concerning Baytex's approach to executive compensation as set forth in Baytex's information circular and proxy statement dated March 20, 2026, be approved.

I, James Maclean, second the motion.

Have any comments or questions been submitted by a registered shareholder or proxy holder?

Mr. Chair, no questions have been submitted.

As voting has been enabled for all previous motions, if a shareholder has not voted yet, please do so. We will close voting shortly.

[Voting]

Voting is now closed. I have been advised by the scrutineers that all resolutions have been approved by more than the requisite majority and that those nominated have been duly elected as directors of Baytex.

I declare the motions carried and the nominees for the Board of Directors elected. Detailed voting results will be press released within 48 hours.

I would now entertain a motion that the meeting be terminated.

I, Chad Kalmakoff, move that this meeting be terminated.

I, James Maclean, second the motion.

I declare this meeting terminated. Thank you for attending this year's shareholder meeting.

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp Fourth Quarter 2025 Financial and Operating Results Conference Call.

As a reminder, all participants are in listen-only mode, and the conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

Thank you, Ashida. Good morning, and welcome to Baytex's fourth quarter full year 2025 results conference call. Joining me today are Eric Greager, our CEO; Chad Lundberg, our President and COO; and Chad Kalmakoff, our CFO. 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.

On the call today, we will also be discussing the evaluation of our reserves at year-end 2025. These evaluations have been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects between the United States or other disclosure standards. Our remarks regarding reserves are also forward-looking statements. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. And after our prepared remarks, we will open the call for questions from analysts, webcast participants can also submit questions online. So with that, let me turn the call over to Eric.

Thanks, Brian. Good morning, everyone. 2025 was a defining year for Baytex. With the closing of the Eagle Ford sale in December, we successfully completed the repositioning of this company into a focused, high-return Canadian oil producer. This is our first call since that milestone and a significant upshift in the trajectory. Baytex is a technically driven organization with an industry-leading balance sheet by exiting the year in a net cash position, we have established a premier platform built for discipline, long-term value creation. We are entering 2026 with a clear strategy and the financial flexibility to navigate any market environment. With this strategic pivot now complete, it is the right time to formalize our leadership transition. As we announced yesterday, Chad Lundberg will succeed me as CEO following our AGM in May.

Chad has been a valuable partner to me and to this organization and his promotion is the result of a deliberate structured succession process to help ensure our positive momentum remain interrupted. I have complete confidence in Chad's leadership and ability to drive our next chapter. I'm proud of the foundation we've built together. Baytex is in excellent shape, and I look forward to its continued success under Chad's leadership. I now turn the call over to Chad Lundberg for his remarks and a detailed operational overview.

Thank you, Eric. I appreciate the Board's confidence, and I'm excited to lead Baytex and our team into the next chapter. My focus as we move forward is simple. We remain committed to technical leadership and disciplined capital allocation to create value. We will continue to build our business by prioritizing our heavy oil and Duvernay assets with an enhanced focus on exploration and new play development, all of which is underpinned by a balance sheet that is in great shape and we will prioritize a competitive return through a combination of organic growth, share buybacks and dividends.

Let's turn to our operational performance. In 2025, our Canadian portfolio delivered annual production of 65,500 BOE per day, which, excluding dispositions, represented 6% organic growth year-over-year. We invested $548 million in Canada in a highly efficient capital program and delivered solid reserves growth, low F&D costs and healthy recycle ratios across all reserve categories. Our Pembina Duvernay and heavy oil development contributed significantly to this performance and continued a strong track record of value creation. This demonstrates the long-term resiliency and sustainability of our business.

Importantly, we have significant running room across our portfolio and are excited about our business going forward. First, let's talk about the Duvernay. We have assembled a 91,500 net acres and identified approximately 210 drilling locations. 2025 was a breakthrough year. We validated the resource potential, reduced well costs on a per foot basis and improved our characterization of the play. We grew production to 10,600 BOE per day in the fourth quarter, a 46% increase over Q4 2024. We are now transitioning to full commercialization with plans to bring 12 wells on stream this year, a 50% increase over 2025.

We currently have 1 rig drilling a 4-well pad on our southern acreage. Completion operations are scheduled for the second quarter with the wells expected on stream by midyear and the remaining 2 pads in the third and fourth quarters. Shifting to heavy oil, we continue to see strong, predictable performance across the portfolio. Our heavy oil assets comprise 750,000 net acres and 1,100 drilling locations, supporting 12 years of drilling at our current pace of development. In total, we expect to bring 91 heavy oil wells on stream in 2026. We are pleased with the expansion of our Northeast Alberta acreage, where we are currently targeting 7 discrete horizons in the Mannville stack.

Recent success includes 2 multilateral wells in the Sparky and a 5-well pad in the upper Waseca. Our 2026 program will also see increased exploration activity, including stratigraphic tests, step-out wells and 3D seismic to expand our development inventory and test new play concepts across our extensive heavy oil fairway. In addition, we are advancing 2 waterflood pilots Peavine blending the attractive capital efficiencies of multilateral primary development with the potential for enhanced recovery and moderated decline rates. Thank you to our teams for executing safely through 2025 and into 2026. And with that, I'll turn the call over to Chad Kalmakoff to discuss our financial results.

Thanks, Chad, and good morning, everyone. Our 2025 financial results demonstrates the cash-generating power of our Canadian assets and the transformative impact of the Eagle Ford divestiture. For the full year, we generated $1.5 billion in adjusted funds flow and $275 million in free cash flow. In the fourth quarter, we delivered $262 million of adjusted funds flow and $76 million in free cash flow, which included $35 million of nonrecurring expenses related to the Eagle Ford disposition.

This was achieved despite a softer commodity backdrop with WTI averaging USD 59 per barrel during the quarter. The 2025 net loss of $604 million reflects the nonrecurring loss on the Eagle Ford disposition, a deferred tax expense related to the restructuring from the sale and $148 million impairment on our Viking assets. These noncash adjustments have no impact on our cash flow generation outlook for 2026. Turning to the balance sheet. We exited 2025 in the strongest financial position in Baytex's history. We eliminated our net debt and ended the year with $857 million in cash less bonds and our $750 million credit facility fully undrawn. We remain committed to returning a significant portion of the Eagle Ford proceeds to our shareholders and believe the NCIB program is the most efficient approach. Since reinitiating our buyback program in late December, we have repurchased 30 million shares, nearly 4% of the company for $141 million.

Our current NCIB remains active through June, and we intend to launch a renewed NCIB in July. As we monitor the broader macro environment, we continue to assess the pace and mechanism of our buybacks to ensure we're maximizing the long-term value for our shareholders. We have considered an SIB or substantial issuer bid, but at this time, we believe we can meet our shareholder commitments through our NCIBs in 2026, while maintaining our annual dividend of $0.09 per share. I'll now turn the call back to Eric for closing remarks.

Thanks, Chad. To build on those points, this focused, high-return Canadian company is the next chapter for Baytex. For 2026, our operations are on track and our annual guidance of 67,000 to 69,000 BOE per day remains unchanged from December, with the high end of that range representing 5% organic growth year-over-year. We have significant inventory depth and optionality across our portfolio to support our current plan and potentially accelerate growth beyond these levels. I'm proud of the trajectory we've established. We are now positioned to demonstrate the true potential of this Canadian portfolio. Operator, let's open the call for a line of questions.

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

Congrats to both of you on the transition. Yes, I'll just start with the 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.

Thanks, Menno. It's Chad. I'll take a crack at answering your question. So on growth, yes, I mean, we've guided to a capital program of $550 million to $625 million, delivering 67,000 to 69,000 barrels a day which represents 3% to 5% production growth. We're actively monitoring the macro kind of picture and situation right now and we would expect to make any decisions on increased growth at the breakup time frame. 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 will come. 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. So 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 utilized the 2 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.

Terrific. And then maybe I guess my second question relates to your opening comments on some of the comments that you made on the Peavine waterflood opportunity. Like 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 to 18 months?

So we're deploying 2 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 we produce 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 waterflood 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 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 waterflood 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 Menno where we go.

Can you remind me, I should know this, but when is the last time Baytex dabbled in waterfloods, if at all?

Yes. So I mean waterflood is not new to Baytex at all. We've actually been at it for 2 decades. Waterflood 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 Menno, approximately 10% of our heavy oil production so 43,000 barrels a day is waterflood derived production. So not new to the story, and it's not foreign to us. We've got technical capacity and teams to really, we think, advance this forward.

That's all the questions we have from the phone lines. I would like to turn the conference back over to Brian Ector for any questions received online. Please go ahead.

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

Well, we set the budget out 3% to 5% centered at $60 oil, guiding to the high side, more than 5% at $65. And certainly, the flexibility is we've built the program to pull that back below $60 oil. I think that's how we 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 so desired.

Another question on the operations around our cost of production. And just can you speak to the capital efficiencies, meaning that you see in the business generally chat and steps we can take to continue to work on the cost of production and efficiencies overall.

Yes. Brian, I think that gets into how we've laid out the budget for 2026. We've started a 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 3 years and then falls off post 3 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, a 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 flows 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 some of the wells that we released through Q4 of last year, up in the Sparky in the southern area, some of our upper Waseca wells as we step through that Northeast Alberta area and the 7 different layers in the Mannville 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.

Chad. Let's shift gears to a couple of questions and conversations around the net cash balance sheet that we have. It's around $800 million and Chad just I know we've talked a little bit about the NCIB in the prepared remarks, but how did we see allocating that $800 million going forward?

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 Kalmakoff in his prepared remarks, talked about the NCIB 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.

Maybe along those lines then, Chad, just when you look at buybacks, how would we evaluate kind of the market price, the value and where we see value in the buyback program itself.

Yes. So I would start here about 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 3 things we look at. One is the macro commodity environment. And so we'd like to think about really acting countercyclically 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 a 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 to 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 3 of those combined would anchor the conversation for how we proceed forward with buybacks. I guess when we look at those altogether today, it would still signal that we are focused on the buybacks and continuing forward from here.

Excellent. One question I turn over to Chad Kalmakoff, our CFO. Chad, can you just talk to our -- the existing hedges in place, maybe WTI and WCS, what the policy will look like going forward?

Sure. We have hedges in place kind of through the back half of last year, collared structures put for us at 60. Through the transaction, we maintain those. So we'd be roughly, I'll call it, 60% hedged on TI Q1 and about 50% -- 45% to 50% hedged in Q2. 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 we obviously have a very pristine balance sheet. I wouldn't expect us to be looking to hedge WTI contracts really in the future, given the balance sheet we have today.

That being said, I think we can still look at hedging WCS contracts. We're 45% to 50% hedged on WCS this year at about $13. We still think that's an important piece of business to keep hedging to kind of prevent any 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.

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. For those who submitted webcast questions that we didn't get to address, please reach out to our Investor 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.

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. Third Quarter 2025 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 Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

Well, thank you, Michael. Good morning, and welcome to Baytex's Third 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.

With that, let me turn the call over to Eric.

Thanks, Brian, and good morning, everyone. Q3 was a strong quarter for Baytex. We delivered record production in the Pembina Duvernay, generated robust free cash flow, supported by the strength and reliability of our Canadian heavy oil and U.S. Eagle Ford operations and made further progress on debt reduction.

Pembina Duvernay set a new quarterly production record averaging just over 10,000 BOE per day, driven by strong well performance from the third pad we brought on stream in September. We also completed a land swap to consolidate our Southern Duvernay acreage and commission new gathering and midstream infrastructure with Gibson Energy, both of which will support more efficient development as we scale up.

Our heavy oil and Eagle Ford assets continued to deliver steady volumes and strong cash flow. Heavy oil production grew 5% quarter-over-quarter, while volumes in the Eagle Ford were up 3%.

Commodity prices remained soft in the third quarter with WTI averaging approximately USD 65 per barrel, but our strong operational execution and cost discipline enabled us to generate $143 million in free cash flow and reduce net debt to $2.2 billion.

With that, I'll turn the call over to Chad Kalmakoff to discuss our financial results.

Thanks, Eric. Third quarter financial results were solid. Adjusted funds flow was $422 million or $0.55 per basic share. Net income for the quarter was $32 million, and we generated $143 million in free cash flow after $270 million in exploration and development expenditures. We returned $17 million to shareholders through our quarterly dividend and reduced net debt by $50 million, bringing net debt at quarter end to $2.2 billion, as Eric noted.

Our financial position remains strong. We have significant financial liquidity with over $1.3 billion in undrawn credit capacity on our credit facilities and our first note not maturing until April 2030. Our capital allocation framework remains unchanged. 100% of our free cash flow is directed to debt repayment after funding our dividend.

Based on year-to-date results and the forward strip for Q4, we now expect to generate approximately $300 million in free cash flow for 2025. This compares to our previous forecast of $400 million, with the change largely attributed to lower commodity prices during the second half of the year. There is no change to our production guidance, and we expect to reach $2.1 billion of net debt at year-end.

I'll pass it on to Lundberg -- Chad Lundberg to provide more details on our operating results.

Thanks, Chad. We saw strong operating performance in Q3. Production averaged 151,000 BOE per day, with liquids making up 86% of the mix. We invested $270 million in exploration and development and brought 69 wells on stream, keeping us on track with our plan.

In the Pembina Duvernay, production averaged 10,200 BOE per day, up 53% from last quarter. The third pad from our 2025 program came online in September with 2 wells delivering strong 30-day peak rates averaging 1,300 BOE per day per well. The third well encountered casing issues during completion and was subsequently abandoned.

We are committed to accelerating full commercialization of the asset, targeting 18 to 20 wells per year by 2027 and ramping production to 20,000 BOE per day by 2029.

In addition to our progress in the Duvernay, we continued to expand our heavy oil platform. Heavy oil averaged 47,300 BOE per day, up 5% from Q2. We brought 20 net wells on stream and expanded our core land base in Peace River and northeast Alberta. Our heavy oil inventory now totals approximately 1,100 locations, supporting approximately 10 years of drilling at our current pace.

Eagle Ford production remained steady at 82,800 BOE per day, with oil production up 3% from last quarter. We brought 15.6 wells on stream while achieving a 12% improvement in drilling and completions costs.

We continue to see strong results from the refracs completed last quarter. Those wells are performing in line with expectations and are informing our plans for an expanded refrac program in 2026.

Overall, operational execution across the asset base remains strong, underpinned by our commitment to health and safety of our workers and the communities in which we operate.

Let me turn the call back to Eric for his closing remarks.

Thanks, Chad. Our third quarter results demonstrate Baytex's ability to create value across commodity price cycles. The Pembina Duvernay continues to drive our Canadian growth potential, bolstered by recent consolidation efforts and infrastructure advancements that support future development and operational flexibility. At the same time, our heavy oil and Eagle Ford assets continue to deliver reliable results and cash flow.

Our capital discipline and our consistent performance demonstrate our ability to execute through market volatility, maintain financial flexibility and position our company for long-term value creation.

Brian, back to you.

All right. Thanks, Eric. Before we open the line for questions, I want to address the recent news reporting regarding our U.S. Eagle Ford assets. As a matter of policy, we do not comment on speculation. Our focus remains on consistent operational execution, capital discipline and maximizing value. We ask that analysts' questions remain focused on our third quarter results and published guidance.

And operator, we're now ready for questions.

[Operator Instructions] First question comes from Phillips Johnston with Capital One.

My first question is on the $24 million of acquisitions that you executed here in Q3. I'm guessing that was spread out across the 3 areas mentioned in the release. Should we assume that -- I guess, the question is, was there any material production that came with the transactions? Or was it all undeveloped acreage?

Phillips, it's Eric Greager here. Thanks for the question. It was all undeveloped land, focused in the Ardmore area, that's Cold Lake oil sands Mannville stack development; in the Peace River oil sands Pekisko area, that one is quite a bit bigger. So the Ardmore was about 4.5 net sections, and the Peace River oil sands at Pekisko area, about 40.5 net sections. That's in the heavy oil business.

And then, in Spartan, likewise, focus just -- sorry, in Pembina Duvernay, likewise, it's just our areas in the South in what we call Gilby, and that was an area that was prior checkerboarded.

Okay. Great. Makes sense. And as you mentioned, we saw a nice uptick in your heavy oil production. It was up 7% in Q2, and then, up another 5% or so here in Q3, and that was after 3 sequential quarterly declines. Can you talk about what's driven that growth? And what we should expect for Q4 and into 2026?

Yes. It's a little early for 2026, but what I would say is we continue to execute the 2025 plan. It's really been, but for the change we made in May after -- in April, May, after Liberation Day after our Q1 announcement, it's really been executing our plan. So we lay out our capital profile based on breakup and anticipation of some breakup impacts to access. And if breakup is light, then that creates optionality in the plan. But we're really simply executing the plan, and we're seeing stronger performance across all of the assets really based on the capital investments we're making. So it's really steady execution of the plan, Phillips, with a little bit better performance than maybe we had originally communicated to the market, which is pretty consistent with our conservative guidance style.

And your next question comes from Luke Davis with Raymond James.

Doing some good work in Canada. I'm wondering if can you just provide some parameters sort of by asset in terms of what you expect those to look like, say, over the next 3 to 5 years. And have you kind of contextualized that in the current commodity price environment versus something a little bit more favorable, call it, mid-cycle price?

Sorry, what assets did you say?

Canadian, general.

Okay. Yes. Luke, it's Eric again. Yes. So look, I think 2026 commodity pricing is anyone's guess, but if things go into the 50s, we're probably looking at a plan that is more conservative. That is what you would expect, and I think what any producer of a commodity would do, something that's probably closer to flat.

If prices move higher toward mid-cycle through 2026 and into 2027, then naturally, we would lean in because there's a lot of value to pull forward for shareholders. I'm sure that's what you would expect me to say. The assets are just performing really well. I mean, we've got strong geology teams working all across our heavy oil fairway, the engineering teams and our long history across our large heavy oil fairway means the hit rate is pretty good on exploration and development.

And in Duvernay, it's just been a really strong year in terms of fracture complexity, completion uniformity, well performance on the whole, and we couldn't be more pleased with the results across our Duvernay as well. So across the Canadian portfolio, it just feels really good. Our Viking assets run steady and flat and are extremely reliable in terms of their input and output factors. So that's the way I would characterize it.

All right. That's helpful. I'm wondering also if you could just dig into the Duvernay a little bit more. Well performance looks very good. I'm wondering if there's anything that you can tweak going forward, and how you'd expect sort of the productivity parameters to change? And then, you did abandon 1 well, so I'm wondering if you can just flesh out some of the issues you had and maybe some learnings coming out of that.

You bet, Luke. I'm going to pitch it over to Chad Lundberg here for that one.

Great. Thanks. Two parts to your question, so I'll address the hole first. This was an issue that resulted from the construction of the well really on the upfront drilling. So it's something to do with the casing and the cement. We believe it's an isolated incident and that we will have it resolved for our programs forward. So I think that's the key thing is we believe it's isolated, and go forward, we've figured it out.

Your second question, just on Duvernay performance, so yes, year-over-year, we've seen a strong improvement in IPs. As everybody knows, we're curiously declining the wells to try to understand how that relates to EURs. We think we have a high chance of seeing an improvement in EURs as well.

When you really think about how we constructed this year, we're trying to understand completion efficiency and just our ability to deliver sand and energy into the formation. We think we made big strides this year and that, that some of these results are a direct result of that.

As we think about programs forward, we're not done. And I don't know if we'll ever be done. These things are a continuous improvement cycle. But we do have more improvements that we're working through at this point in time that we're excited to deploy through 2026 and see where the results take us.

This concludes the question-and-answer session from the phone lines. I'd like to turn the conference back over to Brian Ector for any questions received online.

Thanks, Michael. We had a couple of questions come in on the webcast, but I do believe they've been addressed through the analysts' Q&A already. So I think with that, we are going to wrap up today's call.

I'd like to thank everyone for joining. And thanks again for your time, 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.