Prepared remarks
Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. Second Quarter 2026 Financial and Operating Results Conference Call. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity for analysts to ask questions using the form in the lower section of the webcast frame. I would now like to turn the conference over to Chris Lessoway, Vice President of Finance and Treasurer. Please go ahead.
Thank you, operator. Good morning, and welcome to Baytex's second quarter 2026 results conference call. Joining me today are Chad E. Lundberg, our President and Chief Executive Officer; Kendall Arthur, our Chief Operating Officer; and Chad L. Kalmakoff, our Chief Financial Officer. Before we begin, please note that our discussion today contains forward-looking statements within the meaning of applicable securities laws. I refer you to the advisories regarding forward-looking statements, oil and gas information, and non-GAAP financial and capital management measures in yesterday's press release. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. After our prepared remarks, we will open the call for questions. Webcast participants can also submit questions online. With that, let me turn the call over to Chad E. Lundberg.
Good morning. Q2 was another strong quarter. Production averaged 71.2 thousand BOE per day, above the high end of our guidance for the second straight quarter, with continued outperformance across our heavy oil portfolio and first well results from our southern land block in the Duvernay that we call Gilby. We repurchased 22 million shares for $139 million and exited the quarter with net cash of $566 million. With strong well performance to date, full year production guidance has been raised to 71 thousand BOE per day, up 1 thousand from the midpoint of prior guidance, with a targeted exit rate of 72 thousand BOE per day. There is no change to our capital program of $625 million. Momentum is building. With a renewed interest in Baytex, we continue executing our strategy. We have a clean balance sheet, deep inventory, and a team executing with discipline. Our Q2 results reflect that. I am pleased to announce the appointment of two new directors, Derek Evans and Deanna Zumwalt. These appointments enhance an already strong Board with depth in resource development and energy finance that is directly relevant to our strategy: growing production, capitalizing on opportunities in our portfolio, and building toward our 15% total shareholder return target. Thank you, Steve Riney and Jeffrey Wojahn, for your significant contributions to Baytex. I will now turn the call over to Kendall to walk us through operations, including our heavy oil and Duvernay results, the waterflood pilots, and our second half program.
Thanks, Chad. Production of 71.2 thousand BOE per day exceeded the high end of guidance, representing 11% growth relative to Q2 2025. We invested $122 million on exploration and development and brought 24 wells on stream, consistent with our full year plan and weighted to deliver strong production in the back half. Heavy oil was strong across the board. At Peavine, six of the wells brought on stream during the quarter have established average IP30 rates of 478 barrels per day per well. Results in Peavine continue to outperform internal expectations as development expands from the core. At Lloydminster, seven Mannville wells were brought on stream across multiple horizons. The stack keeps delivering; our multilateral and circulation steam capabilities are a significant advantage here. At Peace River, activity picked up after spring breakup and we are on track with second half development now underway. We have an active second half plan throughout our heavy oil portfolio, with four rigs running and a fifth starting in Morinville in August. On waterfloods, both initial Piedmont pilots are now on injection—one testing repressurization through producer-to-injector conversion, the other testing pressure maintenance on new development. We are expanding waterflood pilots in the second half with two additional patterns at Peavine and a REX formation test in Morinville; both are expected to be on injection by Q4. At Utikuma, the 21-square-mile seismic program is complete, covering roughly 20% of our 109-section land position. Initial interpretations confirm the presence of Pekisko mounds and we are preparing for up to two exploration test wells in early 2027. In the Duvernay, the first pad was drilled on our South Gilby acreage and came on stream in June. Three of the four wells delivered average IP30 rates of 46 BOE per day per well with 88% liquids—amongst our strongest results in the Duvernay on a length-normalized basis. The fourth well was completed at half lateral length after the bottom hole assembly became stuck during drilling and was unrecoverable. This well delivered an IP30 of 866 BOE per day. These results strengthen our confidence in the development opportunity across our southern Duvernay acreage. The second Duvernay pad was drilled on our North Pembina acreage and completion operations are now well underway. This pad is expected to be brought on production in September. The 2026 program is on track: 17 wells drilled, 13 on stream this year, and the last four-well pad to be completed and on stream in early 2027. Q2 was a safe and productive quarter. I want to recognize our operating teams—field and office. Their focus and disciplined execution drove our strong Q2 results. With that, over to Chad L. Kalmakoff to discuss our financial performance.
Thanks, Kendall. Our strong operating results translated into strong financial performance. We generated adjusted funds flow of $254 million in the second quarter, or $0.35 per share. Our operating netback was $55.33 per BOE, up from $35.36 per BOE in Q1, reflecting strong realized pricing and continued cost discipline. As a reminder, on an unhedged basis, every $5 move in WTI impacts our annualized adjusted funds flow by approximately $125 million. The hedges that were in place prior to the sale of our U.S. assets have rolled off as of Q2; we no longer have WTI hedges in place. With a strong balance sheet, we do not anticipate entering into WTI hedges. We generated net income of $175 million in the quarter, or $0.24 per share, bringing year-to-date net income to $108 million, or $0.15 per share. Free cash flow was $128 million, or $0.18 per share, compared to $2 million in Q1. The improvement reflects higher adjusted funds flow combined with investing $122 million on exploration and development. Holding annual capital flat while raising production guidance reflects strong operational performance and cost discipline. During Q2, we repurchased 22 million shares for $136 million at an average price of $6.27 per share, and declared a quarterly dividend of $0.0225 per share payable October 1. Since the sale of our Eagle Ford business in December 2025, we have repurchased 69 million shares, approximately 9% of the shares outstanding, for $378 million. In July, our normal course issuer bid was renewed, providing capacity to repurchase up to 70.9 million shares by July 1, 2027. We continue to be active on the NCIB and anticipate repurchasing $650 million of shares from the proceeds of the U.S. disposition. Our balance sheet remains very strong. We exited the quarter with net cash of $566 million which allows us to execute our plans and be resilient through all parts of the cycle. With that, I will turn the call back over to Chad.
I want to close by putting Q2 in the broader context of where we are headed. The strategy is straightforward: grow production 6–8% annually, capitalize on our heavy oil expertise, commercialize the Duvernay, drive the cost structure lower, and return capital to shareholders. It is that simple. We are targeting a 15% annual total shareholder return at a mid-cycle price of $70 through production growth, dividends, and buybacks—that is the target we are building toward. The commodity price environment this quarter continued to prove constructive with WTI averaging $93 a barrel, and we maintained capital discipline throughout. The increased guidance reflects the quality of our inventory and strong execution from our teams. Heavy oil is the foundation—over 12 years of de-risked drilling inventory, decades of multilateral and circulation steam expertise, active exploration, and waterflood pilots at Peavine that could meaningfully improve long-term recovery. The Duvernay continues to advance: with the first pad now drilled on our southern acreage in Gilby, it confirms high-quality reservoir, strong well results, and verifies inventory as we work towards running a full commercial program by 2027. Gemini Thermal sits beyond the three-year outlook, and we continue to advance our technical and commercial understanding, working towards an FID target of H2 2027. Q2 was a strong quarter for Baytex as we executed our plans and advanced our strategy. I would like to thank our employees and service providers for their tremendous efforts to deliver these results. And lastly, before we open for questions, I want to acknowledge Brian G. Ector. Today is Brian's last day at Baytex, closing out nearly two decades as the trusted voice of this company to the investment community. Brian has worked hard to set myself, Chris, and our company up for success. On behalf of everyone at Baytex, thank you, Brian. It has been a privilege. With that, operator, we are ready for questions.
Questions and answers
We will now begin the analyst question and answer session. To submit your question in writing, please use the form in the lower right. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press *2. The first question today comes from Phillips Johnston with Capital 1 Securities. Please go ahead.
Hi. Thanks for the time, and congrats again to Brian on his well-deserved retirement. My first question is for Chad L. Kalmakoff. You just affirmed, I guess, the target of $650 million of buybacks for this year in your prepared remarks. You are about halfway through, I think, at the end of June. If we look back at the monthly activity within the second quarter, it looks like there was some price sensitivity. It looks like you guys dialed back some activity in May when share prices were floating around $7 a share. And I know at one point you guys were considering an SIB to accelerate the buyback. So my question is: are you still—how opportunistic are you guys planning on being in terms of the share price in order to avoid procyclical buybacks?
Thanks, Phillips. Generally, we really just like the dollar-cost averaging approach, so we do try to be reasonably steady where we can. We do feel like a fixed dollar amount per day kind of naturally dollar-cost averages to the lower end, so you are buying more at the lower end and less at the higher end. On the $650 million target, we are kind of back to about $2.5 million a day. We probably plan to be fairly steady with that through the back half of the year.
Okay. Have you ruled out an SIB at this point?
Yeah. In fact, we have basically ruled out an SIB today. I think we can meet this commitment through the NCIB. We like the NCIB approach: it is tax efficient, it is dollar-cost averaging efficient, and it is not trying to time the market.
Okay. Perfect. And then maybe a second question for Kendall. Nice to see the strong results on the three Gilby wells. Wanted to ask if those results sort of alter your development strategy for the southern acreage going forward? And do you think the results imply some upside to your inventory assumptions? Or is success there sort of already baked into what you have laid out?
Yeah. Thanks for the question. I think it is early, but obviously, it confirms our expectations for the acreage. In terms of upside at this point in time, it's too early to say or comment further.
Yes. I think, Phillips, the IP30s are great and these wells at 1.63 thousand BOE per day, with 90% liquids, essentially were great results. Some of it was a result of flowing through surface facilities and capacity, and then the second was just a little bit on performance. The question now is where do these trend to with respect to the curve. They are slightly beating right now, but we just need more time to analyze. No change to plans.
Okay. That makes sense. Thanks, guys. Appreciate it.
Thank you. The next question comes from Amir Arif with ATB Capital. Please go ahead.
Congrats on a great quarter. Just a follow-up question on the Duvernay. The results were very strong. I was just curious, did you do anything different on the completion approach out here? Or do you think it is more just a reflection of that southern acreage in terms of the oil cuts and the higher rates?
Thanks, Amir. This is a continuation of a long journey in the Duvernay, and so we are continuing to try new things. Last year was all about near-wellbore uniformity. This year, we are really looking to the far field. As we move the sand and commodity further from the wellbore, can we still build that efficient frac pack to drain the reservoir? So there are nuances with respect to the cluster and BIRF design. We have also been testing different tonnages and water loadings, and you can expect to see more of that through our program this year. In terms of Gilby itself, we did test a higher tonnage loading specifically. But as of right now, it is just pad results; it is rock results, and it is going to take time to really understand the nuances with the completion program.
Yeah. That is helpful color. And then just a second question more on the Peavine injection pilots that you have— the first two are on injection. I was just curious what different pattern design you are planning to test with the two additional pilots that you are planning to do out there? So are the two additional pilots new injectors in combination with new drills?
So injection is on stream at the same time as production. That differs from one of the two original pilots. The first pilot is injection into our original discovery well, a two-leg lateral, where that will be all about fill-up—how fast can we fill the injector that was a producer and then start to see response on the producers. These expanded patterns are just to gain an understanding of, a, slightly different rock so to continue to develop our statistical average of what this looks like, and then second, to observe what happens when we inject at the same time and then start first production.
Okay. So this is very similar to one of your existing injections, but it is a different pattern, different layout, or just different rates that you are planning to send?
Very similar to the second pilot, where it is new injectors and new producers—just a different pad. This pad is further to the west, so slightly different rock.
Okay. That is helpful. And then on the Pekisko mound opportunity set, I know you have run the seismic. Just curious when will you be starting to drill any of those prospects that might be on your lands?
Currently, we are just getting ready for permitting for what would be Q1 2027.
Okay. And do you know what the average cost would be on one of those tests for the Pekisko?
About $2.5 million per well.
Okay. Sounds good. And then just a final question more on the hedging policy. As you have let the hedges roll off, I know you have a clean balance sheet. No need to add hedges, but historically you have put in wider collars to at least provide a floor for your CapEx level spend. Any thoughts in terms of going forward—planning to keep it completely unhedged? Or are you still thinking about maybe having some wider collars out there for some downside protection?
Thanks, Amir. With the balance sheet where it is today, we are not looking to do any more WTI hedges; we will just let it flow with the commodity.
Sounds great. Thank you.
Thank you. The next question comes from Dennis Fong with CIBC World Markets. Please go ahead.
Hi, good morning. Congrats on a strong quarter. And again, as well, to Brian Ector. Thanks for taking my question. My first one is maybe continue to focus on the Duvernay. You have obviously seen cost efficiencies as you continue to evolve the way you are developing it. Are you seeing anything further as you move to a little bit more of a commercial-style development and maybe ramp up the level of activity as well? Can you talk through some further innovations or tweaks to your development model—how you think about completion design and so forth as you evolve through the play?
Sure. Just as a reminder, in 2024 we were about $11.50 per foot total DCE costs; last year, $10.50 per foot; this year, $10 per foot; and our target is $9 per foot. That has been a steady improvement in efficiency through the process. We are continuing to see efficiencies and expect to have a full cost reconciliation come out in Q3 as we are only on the second pad. We are currently fracking the second pad right now. On the drilling rig, we are starting to see further efficiency going to the 17 wells per year now that we have committed to drill in 2026, and then some on the completion rigs. To be very specific, some of the work we are doing with cluster designs not only could help with potential performance increase, but could help on the cost-efficiency side—if we can place commodity in the ground in a more efficient way, maybe we can put less in to garner the same results. We have gone to trials on wellsite gas where we are actually using gas right at site to power the frac equipment; that has been pretty exciting. Some of the work we are doing with mud systems, centrifuges for further processing of drilling muds at surface before they go back into the well to drill with, are helping to improve costs on the drill side. Lastly, on infrastructure, we completed in Q2 our second of five main water reservoirs. That will also help with respect to the amount of lay flat we have to lay to ultimately frac the wells. So it is a variety of fronts—kind of all fronts, not just drilling.
Great. I appreciate that color. Switching over to Gemini, I appreciate your comments about moving towards a decision in late 2027. Can you talk to what is left in terms of work to feel comfortable moving forward with an FID on Gemini and how to think about the items you are balancing going into a potential sanctioning of that project?
Yeah. So there are three main things. First, we have continued to add to our Gemini team—we had a skeleton crew coming into Baytex, and we have now got three incremental team members, great hires that we are really excited about advancing it forward. So the engine is running full steam ahead. The three things we are reacquainting with: first, subsurface characterization—furthering our understanding of the rock models and deliverability; second, surface facilities—there has been a lot of work done in the last decade with respect to small-scale modular SAGD operations and technological advancements, so we are just getting our hands around that and ultimately the capital costs; and third, regulatory—regulatory has been a big part of our world for the last decade. There is significant optimism and it looks like there could be movement to help incentivize new growth in the province. We are really just getting a pin in the regulatory framework and how that intersects with the other two items. Great.
Really appreciate that color. I will turn it back. Thanks.
This concludes the question and answer session from the phone lines. I would like to turn the conference back over to Chris Lessoway for any questions received on the webcast. Thanks, operator.
Several questions here. I will start with one for Chad L. Obviously, some cash on the balance sheet here at Q2. Maybe talk a little bit about how that cash is invested and what kind of rate we are earning on that cash?
Thanks, Chris. We do keep cash within the Canadian chartered banks within our syndicate and generally keep it liquid in savings accounts to have quick access all the time. We are generally getting around 2.75% on cash invested.
Greg, thanks Chad. I will follow this up with a question on debt as well. So a small portion of the USD bonds remain outstanding currently. Maybe talk about plans for those going forward and how we intend to fund them?
Prepayment rules: yes, we still have the stub bonds left over from the Eagle Ford disposition. They are fine in the capital structure for now. I think the first call on those bonds would come next March, with the opportunity to take them out if we felt that was the right idea. We have cash on hand to do that. We would not be looking to do any other funding alternatives to take those out—those will just be funded with cash on hand.
Perfect. Thanks, Chad. Couple questions here on the waterflood. I will point these to Kendall. Maybe a couple comments on milestones we are working towards on the pilots—what are you looking to see? And then a second question: where is the water coming from, and talk about availability as we expand those pilots.
Sure, Chris. First, on the water and where it is coming from: that is produced water from the field currently, so we have sufficient water volumes produced for the pilots we are undertaking right now. Subsequently, if we were to move into commercial operations, we would have fairly dedicated source wells in a similar formation with no expectations of challenges there. With respect to what we are looking to see, probably in a 12- to 18-month time frame, depending on injectivity, we would start to see deviation from primary base decline rates and then also GORs becoming suppressed. The very first thing is on the injectivity front—that is something we are going to have a handle on right away. So several markers.
Thank you. Last question here: we remain listed on the New York Stock Exchange—maybe talk about that going forward?
Yes. We are obviously on the NYSE. No plans to change that at all. You can expect us to trade on the NYSE for the foreseeable future.
Perfect. So I think that wraps everything up for today. Thanks everyone for joining our call. For those of you who submitted webcast questions that we did not get to, please reach out to our Investor Relations team and we will follow up directly. Thanks again for your time today, and have a great day.
This brings a close to today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.