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.

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 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 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 Chief Operating Officer role, and Adrian Blazevic has been appointed Vice President, Heavy Oil. I have worked closely with both for the past eight years.

They have been instrumental in building our Canadian operations, and are central to our long-term leadership plan. I am confident in their ability to execute and deliver against the strategy you will hear about this morning.

Kendall, over to you.

Thanks, Chad, 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 onstream, 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 average 30-day IP rates 680 barrels per day, well above the expected tight curve.

At Lloydminster, we stepped up to three rigs during the quarter, successfully targeting seven discrete horizons across the Mannville stack, bringing 16.7 net wells onstream. At Peace River, we brought three wells onstream and acquired an additional 40 sections at Utikuma, 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 onstream in June, with the nine following in Q3 and Q4, totaling 13 wells onstream 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 Kalmakoff.

Thanks, Kendall. This marked our first full quarter of results for our Canadian business.

We generated $152 million of adjusted funds flow, or 20 cents per basic share. 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 2.25 cents 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 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 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 forward 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.

Hi, thanks for the time. 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. If we assume that the new three-year growth rate is around 7%, and you add the 1.5% base dividend yield to that, you need another 6% or so from share buybacks to bridge that gap, which, in round numbers, I think it's around $300 million of share buybacks per year.

My question is, is that math correct? I guess as a follow-up, I realize this year's buyback is going to be significantly north of that figure.

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 three years, or is that a decent placeholder for '27 and '28?

Thanks, Phil. Appreciate the question.

I think this one is very important to be clear on. Yes, at a top line, first priority is to deliver a 15% return to shareholders.

As you said, that's inclusive of production growth plus a dividend plus our buyback program. If we just step back, I just 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.

Great. That clears it up.

Thank you so much. Then wanted to ask 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? Good.

Maybe just a little bit of minor cost inflation we're seeing, no doubt on the diesel side right now. I don't think you could say we have it all baked in to this point in time.

Short of that, no. That is something that we're thinking about.

We've got, though, most of our service supply costs locked in for the year, for calendar 2026 certainly. We'll just have to see.

We're 70 days in to the war, 70 days into a complete flip on a macro basis with respect to supply, demand, and the oil market. Just continue to monitor and see where supply costs go.

Sounds good. Thank you, Chad.

You're welcome.

Thanks. Good morning, thanks for the rundown and congratulations to everyone.

Then Brian, it's been just amazing working with you for such a long time, all the very, very best. Chad, I want to ask you just a little bit about Gemini, and I know when your opening remarks, you did frame 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're approaching this? For example, I know it's been framed that 5,000 barrels a day or so at this point.

Is that a number conceivably that could go up? Then are you assembling a team that's in the organization, just with depth of expertise in thermal?

Thanks for joining, Greg. Let me start high-level.

Gemini has been in the portfolio since 2014. We've identified 300 million barrels of resource on the project.

At a modest 50% recovery, that would put us at 150 million barrels that were targeting to capture. As I said in my comments, we have regulatory approval for phase one of the project to develop it out.

What does that mean? It means we have 3D seismic shot, we have vertical stratigraphic test wells to identify and confirm the chamber, and ultimately that gave confidence for the approval.

That would be phase one. If you do the math on the total resource that's available to recover against 5,000 barrels a day, it would put us out at a 75-year RLI.

That would make us think about incremental projects to enhance the production beyond the 5,000. Can we get to 10,000, or maybe a little bit above?

I think there's a chance. What do we have to do?

A bit of the team has been scuttled 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 costs outlook on the project. From there, we're thinking about trying to get to first FID or an FID decision in early 2027.

That means we ultimately have a chance to put first barrels online in 2029. Does that help, Greg?

Chad, it helps a lot. How I feel about thermal, so that's music to my ears.

Maybe just back on the conventional side, because you look at your three-year plan now with a higher growth rate, 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 the sword frame over and over again—but could you maybe just put some context around how your decline curve is going to shift, and then maybe what sustaining looks like over the next maybe two or three years, just in broad strokes?

Sure. As you pointed out, 6 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. 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, though, we have the incremental projects and catalysts that don't sit inside the three-year plan today.

Peavine 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.

Understood. Thanks very much, Chad.

Thanks, and good morning, everyone, and congratulations Eric and Brian. Just maybe I'll start with a question on the balance sheet.

You talked about running net cash under the three-year plan, which is great to hear, but can you maybe describe your philosophy in a little more detail, 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.

Good morning, Menno. I guess first and foremost, we think that a strong balance sheet is paramount for a oil and gas company and the cyclical nature of the commodity.

That would be step one. We've viewed 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 very good reason to take it on.

Great. Thanks for that, Chad.

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 what are the other sort of considerations in sort of getting from 6 to 8, or the other way around? 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 the company, and that's just drive value out to the shareholders, reposition inside Canada with these great assets that we have. When you think about how we do our capital planning, it's really a bottoms-up build-up from the teams.

The question we ask is, what is the best way to run this asset? What does best mean?

Where can you deliver the strongest returns, strongest capital efficiencies to ultimately drive this growth? The fallout is the corporate top-line production.

When we talk about 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 pace, and we have a shot at improving our cash or 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 four rigs essentially that we keep going around the clock with the rigs to build on the crews, the teams, and efficiencies within. I think that's what underpins the growth, Menno, is just coming at it from a point of view of where can we drive the maximum value and returns to the shareholders.

If you look at 2027 with what I just said, and think about capital costs, this year in the press release yesterday we're going to 13 rigs drilled, complete, tied in, and online in the Duvernay. An incremental pad in the Duvernay that's DUC'd into 2027.

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?"

That does. That's great.

Thanks. Thanks again.

I'll turn it back.

Yeah.

Hi, good morning. First, congrats also to Brian as well as Eric, and thanks for taking my questions.

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

I can answer that very directly. If you look in our slide pack on page 10, we outline what we've been doing with Duvernay costs.

So 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 to 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 facilities spending. For example, as we budgeted, it's about $50 million, with the majority of that going to the Duvernay.

We have three years of elevated facility spend in the Duvernay, '26, '27, and '28, at that $35 million range. After that, it drops to $10 million going forward.

That gets us five of seven major anchor batteries completed. That gets us two and a half of five of the water reservoirs completed.

I think just the last point I'd make is the stakeholder relations. We have a absolutely tremendous surface stakeholder team at the company, and the amount of work they've done to complete the formula for how you're successful in unconventionals has been very strong.

Dennis, I 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. It'll be nice to kind of see where the cost structure trends to, especially as you move to a more scalable development.

My next question turns towards the waterflood over at Peavine. I know you're initiating the two pilots with two different styles of 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. Waterflood in Peavine, we're currently drilling and converting our two pilots.

One of the pilots is a conversion of a two-leg lateral that 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 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. I think that as you think about waterflood in general in conventional cold-flow heavy oil, just in broad strokes, typically you get to 7% recovery on primary development, double that with waterflood, again for very broad brush, 15%, and then push to greater than 20 as you go to more of a polymer flood style development technique.

In some of our primary wells, we've surpassed and gone as high as a 15% recovery, seeing tremendous recovery from again the primary production. Just boiling it down, Dennis, we're looking for base decline on offsetting wells, we're looking at how that translates into ultimate recovery factor, and then we're looking for how that ultimately flows straight through to top-line production out of the asset.

We're pretty excited about what it does for the company if it works.

Great. 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 eight discrete development horizons within call it the heavy oil exposure that you guys have.

I see that most of it's coming effectively from the Waseca and the Sparky. Can you maybe characterize the opportunity set that exists from targeting the multitude or the full stack of formations or targets here as you go forward, both from an inventory perspective and even a growth perspective?

We're very excited about this area. Up in Northeast Alberta, we've doubled the land position in the last five years, but we've also opened up the eight different stacks to the layer.

We think about it as a cube of oil in place. You're right, the initial production is from the Sparky formation, and quite frankly, that's what we identified on a map five 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 risked inventory set in heavy oil, approximately half of them sit on this Northeast Alberta property. There is further incremental inventory that we're actively de-risking by way of some of the exploration dollars drilling stratigraphic test wells, and/or just committing to an outright development-style well.

They are $2 million wells, and so at times we'll just push right through to drilling the well. I think the opportunity is large.

As I said, it's a cube of oil in place over eight different layers, and a map sheet that's greater than 100 sections. There's two predominant zones that were producing from right now, but you can see that we're starting to uptick the different layers as we move further out in time.

Look for us to continue to advance and unlock that in the future and in future updates.

Great. Thanks, Chad.

I'll turn it back.

Right, thanks, Dave. We do have several questions coming in from the webcast, and I'll try to summarize a few of them here.

First to Chad Kalmakoff, can you maybe, Chad, elaborate on the hedge book and our hedge philosophy going forward?

Sure. I'll hit the hedge book first.

We still have about 50% of our WTI hedged until the end of Q2. Those have been legacy hedges that we had in place prior to the sale of the Eagle Ford.

As I mentioned in the introductory remarks, once those roll off, we have pretty robust exposure to WTI prices. In terms of philosophy going forward, I think we've always said a strong balance sheet is the best hedge.

We wouldn't be looking to hedge any more WTI exposure, and obviously with our cash position, we're in an enviable spot. Not looking to do any more WTI hedges.

We continue to hedge differentials, WCS, MSW. We're about 50% or sorry, about 40% hedged, 40 to 50% hedged on WCS for the remainder of the year, around 13%.

That's something that we'll probably continue on in the future, to kind of hedge those differentials.

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

At a top line, we talked about the target to deliver 15% returns to our shareholders at $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 style activity that we would like to think we're very, very good at, to enhance and/or extend our current inventory position. With respect to the dividend, Brian, specifically, we pay 9 cents a share today, that depending on where our price is, 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 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. 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 or for 2026 in total.

Then again, you kind of think about the WTI price beyond that, with the $125 million we want $5 on a full-year basis, that would be kind of your notional changes.

Perfect. Thank you.

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.