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Operator: 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. You may also submit questions in writing at any time using the form in the lower right of the webcast frame. Should you need assistance during the conference call, I would now like to turn the conference over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

Brian Ector: Thanks, Dave. Good morning, and welcome to Baytex Energy Corp.’s First Quarter 2026 Results Conference Call. Joining me today are Chad E. Lundberg, our President and Chief Executive Officer; Kendall Arthur, our Chief Operating Officer; and Chad L. 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 will open the call for questions. Webcast participants can also submit questions online. With that, let me turn the call over to Chad.

Chad E. Lundberg: 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 at $625 million, and this 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% 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 Blazovic 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.

Kendall Arthur: 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 NGLs 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 six 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 three rigs during the quarter, successfully targeting seven discrete horizons across the “Van Ville” stack, bringing 16.7 net wells on stream. At Peace River, we brought three wells on stream and acquired an additional 40 sections at Utikima, bringing our total land position to 109 sections.

We completed a 21 square mile 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 nine following in Q3 and Q4, totaling 13 wells on stream in 2026, with one four-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 L. Kalmakoff.

Chad L. 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. Our operating netback improved to $35.36 per BOE, up from $29.30 per BOE in Q4 2025, 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 will turn the call back to Chad.

Chad E. Lundberg: Thanks, Kendall and Chad. I want to close by stepping back from the quarter and speak about the business and the 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 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 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 are excited to show what Baytex Energy Corp. is capable of. Before we open for questions, I want to recognize two people. First, Eric Thomas 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 Energy Corp. to the investment community for many years. He will be retiring in July, and we look forward to working with him through the transition. On behalf of everyone at Baytex Energy Corp., thank you both. It has been a pleasure working with you. With that, we are ready for questions.

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Operator: We will now begin the question and answer session. 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. Our first question comes from Phillips Johnston with Capital One. Please go ahead.

Phillips Johnston: Hi, thanks for the time. I wanted to ask about the new 15% total shareholder return target, which is rather impressive. Just want to make sure I am thinking about it correctly. So if we assume 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 is 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 2027 and 2028 as being significantly lower so that you average around $300 million per year over the three years, or is that a decent placeholder for 2027 and 2028?

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

Phillips Johnston: Okay. Great. That clears it up. Thank you so much. 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?

Chad E. Lundberg: Maybe just a little bit of minor cost inflation. We are seeing no doubt on the diesel side now. I do not think you could say we have it all baked in at this point in time. Short of that, no, that is something that we are thinking about. We have most of our service supply costs locked in for calendar 2026, certainly. And so we will just have to see. We are seventy days into the war, seventy days into a complete flip on a macro basis with respect to supply, demand, and the oil market. We will just continue to monitor and see where supply costs go.

Phillips Johnston: Sounds good. Thank you, Chad.

Operator: And the next question comes from Greg Pardy with RBC. Please go ahead.

Greg Pardy: Thanks. Good morning. Thanks for the rundown and congratulations to everyone. And Brian, it has been just amazing working with you for such a long time. So all the very, very best. Chad, I want to ask you just a little bit about Gemini. I know in your opening remarks you framed it and indicated that it would be beyond the three-year plan as you look at it. What are the next steps in terms of how you are approaching this? For example, I know it has been framed at 5,000 barrels a day or so at this point. Is that a number that conceivably could go up? And then what about the team you are assembling within the organization, with depth of expertise in thermal?

Chad E. Lundberg: Okay. Thanks for joining, Greg. Let me start high level. Gemini has been in the portfolio since 2014. We have identified 300 million barrels of resource on the project. At a modest 50% recovery, that puts us at 150 million barrels that we are 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 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 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 is 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 are very excited about. We are relooking at the commercial, technical, and capital cost outlook on the project. From there, we are thinking about trying to get to an FID decision in early 2027. That means we ultimately have a chance to put first barrels online in 2029. Does that help, Greg?

Greg Pardy: Chad, it helps a lot. You know how I feel about thermal, so that is 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, with that comes higher decline rates, higher natural declines, and then also higher sustaining. Could you maybe put some context around how your decline curve is going to shift and then maybe what sustaining looks like over the next two or three years, just in broad strokes?

Chad E. Lundberg: As you pointed out, 6% to 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, 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 three-year plan, our decline stays actually relatively flat with the growth. On top of that, we have incremental projects and catalysts that do not sit inside the three-year plan today—so Peavine waterfloods that are being piloted right now.

We have incremental project opportunity 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.

Operator: And the next question comes from Menno Hulshof with TD Cowen. Please go ahead.

Menno Hulshof: Thanks, and good morning, everyone, and congratulations Eric and Brian. Just maybe I will 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 describe your philosophy in a little more detail? And is there a scenario you would take on a bit of balance sheet leverage? I am assuming the answer is no, but maybe you could just walk us through that. And then on the outlook for 2027—I understand we will 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%? Oil price, of course, is going to factor in, but what are the other considerations in getting from six to eight or the other way around? And what are the broad strokes in terms of growth, spending, and activity levels based on what you are seeing today?

Chad E. Lundberg: Good morning, Menno. First and foremost, we think that a strong balance sheet is paramount for an oil and gas company given 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 in the past before the Eagle Ford transaction and the repositioning that we have undertaken. As you think about this company going forward, if we did elect to use debt, half a turn at $70, or mid-cycle pricing, would be a threshold boundary that we would not exceed, and there would have to be very good reason to take it on. On your second question, it comes back to what we are really trying to do at the company, and that is drive value out to the shareholders within Canada with these great assets that we have.

When you think about how we do our capital planning, it is really a bottoms-up build 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 and strongest capital efficiencies to ultimately drive this growth? The fallout is the corporate top-line production. When we talk about 6% to 8% in 2027, 2028, and beyond, this moves us, for example, to an 18 to 20 well program in the Duvernay. Again, that is where we hit a one-rig levelized base, and we have a shot at improving our capital cost structure even further than what we have demonstrated to this point in the asset. Equally so in heavy oil, where we would look to run the four rigs—essentially keep them going around the clock—to build on the crews, the teams, and efficiencies.

That is what underpins the growth, Menno: coming at it from a point of view of where we can drive the maximum value and returns to shareholders. If you look at 2027 with what I just said and think about capital costs, this year, in the press release yesterday, we are going to 13 wells drilled, completed, tied in, and online in the Duvernay, with an incremental pad in the Duvernay that is docked into 2027. Next year, 18 to 20 wells. That is 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?

Menno Hulshof: Yeah, that does. That is great. Thanks again. I will turn it back.

Operator: And the next question comes from Dennis Fong with CIBC. Please go ahead.

Dennis Fong: 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. You have obviously showcased very strong well cost improvement in the Pembina Duvernay. As you switch towards a one-rig development program and start to roll in a lot of those efficiencies, where do you think the cost structure can get to within the Pembina Duvernay? And then my next question turns towards the waterflood over at Peavine. I know you are initiating the two pilots with two different styles of waterflooding technique. Can you talk to some of the data points or key metrics that you are looking for or hoping to find in terms of each of those pilots, how that may provide you insight to its possible deployment across your existing field, and the future development of the play?

And if you will permit me one last question, I am looking at slide 12 within your presentation. You have highlighted an opportunity set targeting eight discrete development horizons within your heavy oil exposure. I see that most of it is coming from the Waseca and the Sparky. Can you characterize the opportunity set that exists from targeting the full stack of formations as you go forward, both from an inventory perspective and a growth perspective?

Chad E. Lundberg: I am going to answer that very directly. If you look in our slide pack on page 10, we outline what we have been doing with Duvernay costs. In 2024, we moved from $1,165 per foot to $1,025 per foot of lateral length completed. We are budgeted this year at $1,000 per foot, and we think—this is the power of getting to scale in the asset—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 is the ecosystem of unconventional development. People have to understand what we have done at this company. We talked about costs; we have not talked about characterization. Again, slide 10 points to what we have done year-over-year, 2024 to 2025, on the characterization front, moving from 80 BOE per foot to 90 BOE per foot.

We have not really talked about facilities and water infrastructure, but that is part of the ecosystem that needs to be developed to really optimize and maximize your efficiencies. This year we have a little bit of incremental facilities spending. For example, as we built up budget, it is about $50 million, with the majority of that going to the Duvernay. We have three years of elevated facility spend in the Duvernay—2026, 2027, and 2028—at that $35 million range. After that, it drops to $10 million going forward. That gets us five of seven major anchor batteries completed and two and a half of five of the water reservoirs completed. The last point I would make is stakeholder relations. We have a tremendous surface stakeholder team at the company.

The amount of work they have done to complete the formula for how you are successful in unconventionals has been very strong. On Peavine waterfloods, we are 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. We will be actively trying to observe how fast we can fill up the voidage for oil that we have 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 are 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 attempting to observe what happens with decline and ultimately what that does to the recovery factors on the wells up in Peavine.

Stepping back, we hold 48 of the top 50 wells on primary production in Peavine, and you can see continued strong results with the delivery of primary development in Q1. In broad brush strokes for conventional cold flow heavy oil, typically you get to a 7% recovery on primary development, double that with waterflood to roughly 15%, and then push greater than 20% as you go to more of a polymer flood style development technique. In some of our primary wells we have surpassed and gone as high as a 15% recovery, so we are seeing tremendous recovery from primary production. Boiling it down, Dennis, we are looking for base decline moderation on offsetting wells, how that translates into ultimate recovery factor, and how that ultimately flows straight through to top-line production out of the asset.

We are pretty excited about what it does for the company if it works. On the broader heavy oil opportunity set, we are very excited about this area. In Northeast Alberta, we have doubled the land position in the last five years and opened up eight different stacked layers. We think about it as a cube of oil in place. You are right, the initial production is from the Sparky formation, and that is what we identified on a map five years ago in our long-range planning. With the work that has been done by our technical teams and industry broadly, mapping out the signatures of the Clearwater has opened up the incremental opportunity set here to the Waseca, as you pointed out, the Colony, McLaren, and the various zones within that stack. Of the 1,100 wells that we hold and call a risked inventory set in heavy oil, approximately half sit on this Northeast Alberta property.

There is further incremental inventory that we are actively derisking by way of exploration dollars, drilling stratigraphic test wells, and, at times, committing to an outright development well. They are $2 million wells, and at times we will push right through to drilling. The opportunity is large. It is a cube of oil in place over eight different layers and a sheet that is greater than 100 sections. There are two predominant zones that we are producing from right now, but you can see that we are 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.

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

Brian Ector: Great. Thanks, Dave. We do have several questions coming in from the webcast, and I will try to summarize a few of them here. First, to Chad L. Kalmakoff, can you elaborate on our hedge roll-off—maybe the hedge book and our hedge philosophy going forward?

Chad L. Kalmakoff: Sure. I will 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 WTI prices. In terms of philosophy going forward, I think we have always said a strong balance sheet is the best hedge. We would not be looking to hedge any more WTI exposure and, obviously, with our cash position we are in an enviable spot. So I am not looking to do any more WTI hedges. We continue to hedge differentials—WCS, MSW. We are about 40% to 50% hedged on WCS for the remainder of the year around $13. That is something that we will probably continue in the future, to hedge those differentials.

Brian Ector: And a number of questions are coming in around dividend philosophy and shareholder returns again. Chad, can you elaborate on the thoughts around the dividend versus the buyback program?

Chad E. Lundberg: At the 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 buybacks. 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 think we are very good at, to enhance and extend our current inventory position. With respect to the dividend, Brian, specifically, we pay 9¢ a share today—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 a best returning, risk-adjusted basis, and this is the formula that we are moving forward with.

Brian Ector: One last question around the free cash flow generation of our business. We were a couple million dollars in Q1, Chad. Thoughts on expectations as the year unfolds for free cash flow?

Chad L. Kalmakoff: Sure. I think we expect the balance of the year to be more robust. We kind of touched on the hedges—that 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 at around $250 million of free cash flow for 2026 in total. And then, again, you think about the WTI price beyond that—the $125 million per $5 on a full-year basis—that would be your notional change.

Brian Ector: Perfect. Thank you. So free cash flow will grow as the year unfolds. That covers the questions coming in from the webcast. That does wrap up today’s call and the questions that were coming in. We would like to thank everyone for joining us. Thanks again for your time, and have a great day.

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

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