BTE

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. As a reminder, all participants are in listen-only mode, and the conference is being recorded. After the presentation, there will be an opportunity for analysts to ask questions. To join the question queue, you may press star then one on your telephone keypad. You may also submit questions in writing at any time using the form in the lower section of the webcast frame. Should you need assistance during the conference call, you may signal an operator by pressing star then zero. 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 CAD 591 million and repurchased 35 million shares or 4.6% of our shares outstanding for CAD 174 million. With this outperformance and a constructive commodity backdrop, we are raising our 2026 production guidance to 69,000-71,000 BOE per day. This represents 7% annual growth at midpoint, up from 3%-5% previously. We are maintaining discipline with capital expenditures moving to the high end of our guidance, CAD 625 million, and includes incremental projects in our Duvernay and heavy oil. Along with updating our current year guidance, we are also updating our three-year outlook. With the depth and quality of our inventory, we are targeting 6%-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 Chief Operating Officer role, and Adrian Blazevic has been appointed Vice President, heavy oil. I have worked closely with both for the past eight 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, 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 CAD 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 six wells of our 2026 program averaged 30-day IP rates, 680 barrels per day, well above the expected type curve. At Lloydminster, we stepped up to three 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 three wells on stream and acquired an additional 40 sections at Utikuma, bringing our total land position to 109 sections. We completed a 21 sq mi seismic shoot 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 four wells of the year, with completions now underway. First wells are expected on stream in June, with the nine following in Q3 and Q4, totaling 13 wells on stream in 2026, 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 CAD 152 million of adjusted funds flow or CAD 0.20 per basic share. Our operating netback improved to CAD 35.36 per BOE, up from CAD 29.30 per BOE in Q4 2025, driven by higher realized pricing and continued cost discipline. We realized hedging losses of CAD 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 movement WTI impacts our adjusted funds flow on an annual basis by approximately $125 million. We ended Q1 with a net cash position of CAD 591 million. As Chad highlighted, we repurchased 35 million shares or 4.6% of the shares outstanding for CAD 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 CAD 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%-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 CAD 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 14,000-15,000 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 CAD 50, further enhancing our resilience through the cycle. Gemini Thermal represents significant long-term optionality that sits beyond our three-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're 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.

We will now begin the question-and-answer session. To join the question queue, you may press star then one on your telephone keypad. You will hear a tone acknowledging your request. To submit your question in writing, please use the form in the lower right section of the webcast frame. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star and then two. Our first question comes from Phillips Johnston with Capital One. Please go ahead.

Hi, thanks for the time. Wanted to ask about the new 15% total shareholder return target, which is rather impressive. Just want to make sure I'm thinking about it correctly. If we assume that the new three-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 CAD 300 million of share buybacks per year. My question is that math correct? I guess as a follow-up, I realize this year's buyback is gonna be significantly north of that figure.

Conceptually, should we think about the buyback in 2027 and 2028 as being, you know, significantly lower, so that you average around CAD 300 million per year over the three years? Is that a decent placeholder for 2027 and 2028?

Okay. Thanks, Phil. Appreciate the question. I think this one is very important to be clear on. 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 wanna reiterate the commitment from the proceeds from the Eagle Ford sale. 75% or CAD 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. Thank you so much. 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?

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 in to 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. We'll just have to see. You know, 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.

Sounds good. Thank you, Chad.

You're welcome.

The next question comes from Greg Pardy with RBC. Please go ahead.

Thanks. Thanks. Good morning. Thanks for the rundown and congratulations to everyone. Brian, it's been just amazing working with you for such a long time. 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, you know, frame it and indicated that it would be beyond the, you know, the three-year plan as you look at it. What are the next steps in terms of how you're approaching this? For example, I know it's been framed at, you know, 5,000 barrels a day or so at this point. Is that a number conceivably that could go up?

Are you assembling a team within the organization, you know, just with depth of expertise in thermal?

Thanks for joining, Greg. 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. 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 RLI. That would, 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? 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 re-looking at the commercial, technical, capital costs, outlook on the project. 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 three-year plan now with a higher growth rate, typically with that, you know, 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 two or three years, just in broad strokes?

Sure. As you pointed out, 6%-8% production top line growth over the three-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. I would remind everybody that of the 75%, approximately 10% of our heavy oil is water flood derived at this point in time. If you look across that piece and portion of our portfolio, we have very competitive declines, excuse me, in the space. As we think about that three-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 three-year plan today. Peavine water floods that are being piloted right now. We have incremental project opportunity just across the conventional cold heavy oil production 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.

Understood. Thanks very much, Chad.

The next question comes from Menno Hulshof with TD Cowen. Please go ahead.

Thanks, and good morning, everyone, and congratulations, Eric Greager and Brian Ector. Just, maybe I'll start with a question on the balance sheet. You talked about running net cash under the three-year plan, which is great to hear, but can you maybe describe your philosophy in a little more detail? 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.

Good morning, 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. 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. You know, as you think about this company going forward, if we did elect to use kinda half a turn at that CAD 70 or mid-cycle pricing would be a threshold boundary that we wouldn't exceed, and there would have to be very good reason to take it on.

Great. Thanks for that, Chad. The second question is on the outlook for 2027. I understand we'll have to wait for the release of 2027 guidance for the full details. What are the other sort of considerations in sort of getting from six to eight or the other way around? What are the broad strokes in terms of growth spending and activity levels based on what you're, what you're seeing today?

You know, I think it comes back to what we're really trying to do with the 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 build up from the teams. The question we ask is what is the best way to run this asset? What does best mean? Where can you deliver the strongest returns, strongest capital efficiencies to ultimately drive this growth? The fallout is the corporate top line production. When we talk about 68% in 2027, 2028 and beyond, this moves us, for example, to an 18-20 well program in the Duvernay.

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. 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 an online on the Duvernay, an incremental pad in the Duvernay that's docked into 2027. Next year, 18-20 wells. That's going to come with some incremental capital, and you can expect that to be additive to the CAD 625 million where we sit today. Does that help, Menno?

Yeah, that does. That's great. Thanks. Thanks again. I'll turn it back.

Yeah.

The next question comes from Dennis Fong with CIBC. Please go ahead.

Hi. Good morning. First, congrats also to Brian as well as Eric, and thanks for taking my question. 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, would you think cost structure can get towards with respect to costs for within the Pembina Duvernay?

I'm gonna answer that very directly. If you look in our slide pack on Page 10, we outline what we've been doing with Duvernay costs. In 2024, we moved from CAD 1,165 per foot to 2025, CAD 1,050 per foot of lateral length completed. We're budgeted out this year at CAD 1,000 per foot. 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 CAD 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 kinda year over year, 2024 to 2025 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 facilities spending. For example, as we built our budget, it's about CAD 50 million, with the majority of that going to the Duvernay. We have three years of elevated facility spend in the Duvernay, so 2026, 2027 and 2028 at that CAD 35 million range. After that, it drops to CAD 10 million going forward. That gets us five of seven major anchor batteries completed. That gets us 2.5 of five of 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 has been very strong. Dennis, I try to answer it very direct, broaden the question because there's many things that need to be taken into consideration.

I really appreciate that incremental color. Yeah, like it'll 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 two pilots with two 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 fields and kind of the future development of the play?

I can. Waterflood at Peavine, we're currently drilling and converting our two pilots. One of the pilots is a conversion of a two-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. 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. I think that as you think about waterflood in general and conventional cold heavy oil production, just in broad strokes, typically you get to 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 technique.

In some of our primary wells, we've surpassed and gone as high as a 15% recovery. Seeing tremendous recovery from, again, the primary production. 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, we're looking for how that ultimately flows straight through to top-line production out of the asset. We're pretty excited about what it does for the company if it works.

Great. Great. If you'll permit me one last question here. I'm looking at Slide 12 within your presentation, what you've kinda highlighted there is an opportunity set targeting eight discrete development horizons within, we'll call it the heavy oil exposure that you guys have. I see that most of it's 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. Up in Northeast Alberta, we've doubled the land position in the last five years, but we've also opened up the 8 different stacks to the layer. We think about it as a cube of oil in place. You're right, the initial production is from the Sparky Formation. Quite frankly, that's what we identified on a map, you know, five years ago in our long-range planning. That's what, you know, 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 risked inventory set in heavy oil, approximately half of them sit on this Northeast Alberta property. There is further incremental inventory that we're actively de-risking by way of some of the exploration dollars, drilling stratigraphic test wells, and/or just committing to an outright development style well. They are CAD 2 million wells, at times we'll just push right through to drilling the well. I think the opportunity is large. As I said, it's a cube of oil in place over eight different layers in a map sheet that's greater than 100 sections. There's 2 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. Look for us to continue to advance and unlock that in the future and in future updates.

Great. Thanks, Chad. I'll turn it back.

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.

Great. Thanks, Dave. We do have several questions coming in from the webcast. I'll try to summarize a few of them here. First to Chad Kalmakoff. Can you maybe, Chad, elaborate on 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 the sale of the Eagle Ford. As I mentioned, in the introductory remarks, once those roll off, we have pretty robust exposure to the WTI prices. In terms of philosophy going forward, I think, we've always had a strong balance for the best hedging. We wouldn't be looking to hedge any more WTI exposure. Obviously with our cash position we're in an enviable spot. Not looking to do any more WTI hedges. We continue to hedge differentials WCS, MSW. We're about 50% or sorry, about 40% hedged. 40%-50% hedged on WCS for the remainder of the year, around 13%. That's something that we'll probably continue on in the future to kinda hedge those differentials.

A 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 maybe elaborate on the thoughts around the dividend versus the buyback program?

At a top line, we talked about the target to deliver 15% returns to our shareholders at CAD 70 oil, comprised of growth plus dividend plus buybacks. We talked about CAD 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 style 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 CAD 0.09 a share today. That, depending on where our price is in the 1.5% range, is 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, you know, everything is evaluated on our best returning risk-adjusted basis. 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 CAD million in Q1, Chad, 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 kinda touched on the hedges so that kinda impacts Q2 a little bit. Beyond that, you know, if you think about a CAD 80 average price for the remainder of the year, that would put you into the around CAD 250 million of free cash flow for the balance or for 2026 in total. Again, you can think about the WTI price beyond that. The $125 million, we want $5 on a full year basis. That would be kinda your notional changes.

Perfect. Thank you. Free cash flow will grow as the year unfolds. This 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.