Baytex Energy Corp. Aktie

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.

Good day, everyone. Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. Second Quarter 2025 Financial and Operating Results Conference Call. [Operator Instructions] The conference is being recorded.

[Operator Instructions] I would now like to turn the floor over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

Thank you, Jamie. Good morning, and welcome to Baytex's Second Quarter 2025 Earnings Call. I am joined today by Eric Greager, our President and Chief Executive Officer; Chad Kalmakoff, our Chief Financial Officer; and Chad Lundberg, our Chief Operating Officer.

Before we begin, please note that our discussion today contains forward-looking statements within the meaning of applicable securities laws. I refer you to the advisories regarding forward-looking statements, oil and gas information and non-GAAP financial and capital management measures in yesterday's press release. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified.

And after our prepared remarks, we'll open the call for questions from analysts. Webcast participants can also submit questions online, and we will address as many as time permits.

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

Thanks, Brian. Good morning, everyone. We delivered solid operational and financial results in the second quarter that reflect the quality of our assets as well as our focus on operational excellence. In the Pembina Duvernay, we achieved the highest 30-day peak oil rates recorded in the West Shale Basin. These results validate our technical and operational advances, and help demonstrate the exceptional resource potential within our portfolio.

Beyond the Duvernay, the teams consistently delivered solid execution across our operations. Heavy oil production grew by 7% quarter-over-quarter, while our Eagle Ford team delivered 2 more strong refracs at half the cost of new wells. The commodity backdrop in Q2 was soft with WTI averaging USD 64 per barrel. In this volatile environment, we remain focused on capital discipline, prioritizing free cash flow and reducing net debt.

Our second quarter results demonstrate our resiliency through commodity price cycles, while maintaining capital flexibility. Let me turn the call over to Chad Kalmakoff for our financial results.

Thanks, Eric. We delivered second quarter financial results consistent with our full year plan. Adjusted funds flow was $367 million or $0.48 per basic share, and we generated net income of $152 million. We generated $3 million in free cash flow and returned $21 million to shareholders, including $4 million in share repurchases and $17 million in quarterly dividends.

Balance sheet strength remains a priority. Net debt decreased $96 million or 4% to $2.3 billion, supported by a strengthening Canadian dollar. We repurchased USD 41 million of our 8.5% long-term notes during the quarter as part of our systematic approach to debt reduction. We maintain substantial financial flexibility with USD 1.1 billion in credit facility capacity that is less than 25% drawn and matures in June 2029. Our long-term debt maturity profile provides significant runway with our earliest note maturity in April of 2030.

Let me turn the call over to Chad Lundberg for our operating results.

Thanks, Chad. We're pleased with the operating performance across our portfolio. Production averaged 148,095 BOE per day, a 2% increase in production per share compared to the same quarter last year. Exploration and development expenditures totaled $357 million, consistent with our full year plan, and we brought 67 wells on stream.

In the Pembina Duvernay, our first pad achieved average 30-day peak production rates of 1,865 BOE per day per well with 3,800-meter completed lateral length. The second pad came on stream through early July with similar lateral lengths. And over the last 26 days has averaged 1,264 BOE per day per well. Our third pad is expected onstream in September. The performance of our first 2 pads has exceeded initial rate expectations. With the first pad delivering the highest 30-day peak oil rates to date in the West Shale Basin. These results demonstrate our continued advancement in drilling and completions performance.

In addition to well performance, we achieved a 12% improvement in drilling and completion costs compared to 2024. These efficiency gains strengthen well economics and further support our capital allocation decisions. With 140 net sections and approximately 200 locations identified, we plan to transition to full commercialization through '26 and into '27. This means we would target drilling 18 to 20 wells per year, resulting in production ramping to 20,000 to 25,000 BOE per day by '29, 2030.

In the Eagle Ford, we brought on stream 15 wells, while realizing an approximate 11% improvement in drilling and completion costs. We delivered 2 additional refracs with initial rates comparable to our broader development program at approximately half the cost with 300 refrac opportunities identified across our acreage. This program extends asset duration, while delivering strong capital efficiency. Our heavy oil operations continue their strong performance with production up 7% quarter-over-quarter.

We brought on stream 43 wells across Peavine, Peace River and Lloydminster continuing to demonstrate the capital-efficient development of these assets.

Our team continues to focus on safe and efficient development across our portfolio as we progress through the year.

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

Thanks, Chad. Our second quarter results reinforced the quality of our asset portfolio and our ability to execute through volatile market conditions. The top performance in the Pembina Duvernay highlights the asset's strong value and growth potential, while our heavy oil operations continue delivering strong returns and our Viking and Eagle Ford assets provide reliable cash flow and asset duration.

We remain committed to rigorous capital allocation and regularly evaluate opportunities within our portfolio to maximize shareholder value. The operational achievements delivered in the second quarter provide us with valuable options as we continue to optimize our plans. Based on forward strip pricing, we expect to generate approximately $400 million of free cash flow in 2025 with the majority weighted to the second half of the year given our production and capital spending profile.

We plan to allocate 100% of free cash flow to debt repayment after funding quarterly dividend payments, targeting net debt of approximately $2 billion by year-end.

Looking ahead, our oil-weighted production profile provides significant exposure to oil price upside with approximately 84% of our production weighted towards crude oil and liquids. Every USD $5 per barrel change in WTI impacts our annual adjusted funds flow by approximately $225 million on an unhedged basis. This positions us well to benefit from any oil price recovery. We remain focused on operational excellence, financial discipline and positioning Baytex to deliver sustainable long-term value for shareholders.

Operator, we're ready for questions.

[Operator Instructions]

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

A couple of quick questions. Just with the 12% improvement that you're citing in the Duvernay, can you let us know what your average well cost is averaging up there?

Yes. Thanks, Amir. The average well cost so far this year has been running right at $12.5 million. So for a 12,000-foot lateral, a 12,500-foot lateral, that's right at $1,000 per completed lateral foot. And that's, I think, affords us continued opportunities for improvement as well. So we're targeting a lower value over time, but that's kind of where we stand today.

Got it. And based on the comments of eventually moving to commercialization in '26, '27, should we think about like 1 rig program for '26 like 12-well program next year?

Well, so yes, we are eventually moving in 2027 to a 1-rig levelized program. We think that will generate 18 to 20 wells per year. So a single rig running around the calendar, Amir be an 18 to 20 well base of development. Next year, in 2026, we're targeting 12 to 15 wells. It kind of depends on the balance of the year and kind of commodity price, let's say, in 2026. But we're shooting for 12 to 15, and that continues to step toward full commercialization. We're very pleased. Very encouraged by the opportunity for this commercialization and moving toward full development. But 1 rig will be higher than 12. So next year won't quite get...

Okay. I appreciate that. I appreciate the color there. Just switching over to the Eagle Ford. The IP rates are fantastic. I mean those are essentially like a new well rate. Is the decline rate different post the refracs?

It's still a little early.

Yes. Yes. So yes, the early rates are strong. The pressure performance is strong. Everything we can see so far within the reservoir characteristics, dynamic testing indicates to us that we're touching all new reservoir. And that's really encouraging. But it's a little bit too early on the 2 refracs in 2025 to know really with data specificity around decline rates. But so far, so good. They feel very strong and we have every indication that we're touching new reservoir in these refracs. So that's strong.

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

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

Okay. Yes. I mean it's a combination of 2 things. We're seeing some relief from our service partners with just service cost reductions, most notably, you see drill rig activity levels and frac activity levels in the U.S. It's no secret that they've been dropping, significantly. So we have seen some relief from our service companies on the cost side. We're excited about that. We're probably more pleased with just the continued efficiency gains. We like to measure those in lateral footage per day or completion pump hours per day.

In half 1 this year, we saw another marked improvement over '23 -- '24, '23 was better than Q2. So we just continue to see improvements on the efficiency side.

Lastly, though I'd point to, we made a conscious effort to switch late last year and then through most of half 1 this year to field gas on the frac side. And so instead of burning diesel to power the equipment to put the net energy into the ground, we're able to plug in to the gas flows rate on site.

And so that's a bit of meaningful savings as well. So savings efficiencies and just a little bit different plumbing on lease for how we're capturing it, Amir.

Okay. And then, Chad, if you had to break out that 11% in terms of service cost reduction versus these efficiencies, is there a rough number that you could give?

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

And ladies and gentlemen, with that, we'll be closing the question-and-answer session from the phone lines. I'd like to turn the floor back over to Brian Ector for questions received online.

Great. Thanks, operator. I do have several questions coming on the webcast. Some from our analysts and a few from investors as well.

Continuing with the Pembina Duvernay performance, can we speak to -- Eric, can you speak to the variability across the 3 wells. So we talked about the performance of the 701 pad. There were 3 wells on that pad. Can you speak to the variability? Was there much variability in each of those 3 wells?

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

Yes. So on the -- I mean on the pad itself, they're pretty localized wells. We see consistent performance across them. And then the differences in rates between the pad in the south, the pad in the North. I mean, let's face it, there's rock characteristic differences, reservoir characteristic differences.

And then we are also trialing some different ways that we -- not so much complete the wells, but maybe more on the facility side, the flowback side. And so while we see an IP difference, we think that these naturally will trend to a similar EUR pattern ultimately through time. But the reality is there's going to be differences throughout the play. I think what we're most excited about is these -- both these pads are exceeding kind of certainly our expectations and our internal curves at this point, but it's early. I would just caveat it with it's early, and we'll see where they go from here.

All right. One more question related to the Duvernay. That's on the infrastructure side. Just can we discuss the potential infrastructure spending needed to expand the production in the Pembina Duvernay?

Yes. I mean I think we've got that fairly well characterized right now. I mean, you saw our Gibson deal that we announced last quarter or 2 quarters ago, where they're taking some of the infrastructure burden off of us. We're still pleased with the agreement and the synergies that we're creating with Gibsons. We think facilities, no doubt are going to be somewhat front-end loaded. We think about it as $25 million to $30 million a year for these early years, liberating itself to a lower rate in the out years.

And I think the last note I'd make is some of the major facility when you think about unconventional resource, major facility spend is on gas plants and gas handling. The benefit we have is we're overlaying a cobweb of earlier development that was gassier style development. So we've got gas pipe all through the area.

And then we've got a large gas processing facility with Keyera, one of our partners that's not full. We don't anticipate that it fills through the life of the place. So it's got significant capacity to handle all the molecules we anticipate flowing into the future. Said differently, we don't have to go out and build what we would think as the largest capital contributor to these unconventionals in just the gas processing.

Let's switch to the Eagle for a minute here. We talked about the refracs in the quarter. Eric, how were we looking to layer in capital on the refrac opportunities in the Eagle Ford, given the depth of the inventory there?

Yes. So we are very excited about the refracs. The team has gone from proof of concept last year to 2 really strong successful refracs to follow up the successful proof of concept last year. So couldn't be more excited. We've got 300 opportunities identified in our current base, and we intend to step up the pace of our refracs, bringing those into the program with greater frequency.

So as it stands today, the way we see 2026 is somewhere in the 6 to 10 refracs range. And again, given the economic performance of these and the capital efficiency, we're going to lean on that.

Okay. Eric, on the nonoperating piece of our Eagle Ford asset, those -- that program is now operated by Conoco. They've been operating the wells for about a year post their acquisition of Marathon. Can you speak to any changes in their process or approach with regard to the non-op asset? And our relationship with the operator?

Yes, we've got a great relationship with Conoco. We had a great relationship with Marathon as a significant working interest partner in those Karnes mutual interest areas. We work closely with them. And across the organization, we get good information from them. They're very thoughtful about how they develop. They're very thoughtful about how they plan. They were thoughtful and diligent in their timing of providing us the 2025 program.

They told us to use the one we had until we heard otherwise. They've delivered a new '25 plan to us, and we're satisfied with it. So we believe that we've got a strong relationship, and we believe that the development is going to continue moving forward, and we're very comfortable with the plans that we've seen.

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

Thanks, Brian. Yes, I don't -- our hedging strategy, I don't think has changed. So we're fairly hedged here in 2025. On the oil side, we've been targeting $60 floors and then selling calls on top of that to kind of fund the puts where we can.

So generally speaking, we use it as a bit of an insurance product that $60 floor kind of base in the balance sheet and asset kind of where we start flowing back capital below that $60 floor level. So feeling good about where we have '25. As we look into 2026, we're lightly hedged at this point, but still looking at that same framework where we want to have a $60 a foot floor. Given where prices are today, the calls aren't as high as they were at one time.

But we started layering in a little bit here in Q1. When prices kind of spiked, the backwardation of the curve has still been pretty strong. But we're trying to layer in 60 by kind of low, mid-70s where we can get them, and we'll continue to do that through the balance of this year and look to have 40% hedged by the end of this year as we walk into 2026.

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

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