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Operator: Good day, everyone. Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. Third Quarter 2024 Financial and Operating Results Conference Call. As a reminder, all participants are in a listen-only mode. The conference is being recorded. After the presentation, there will be an opportunity for analysts to ask questions. [Operator Instructions] You may also submit questions in writing in any time using the form in the lower section of the webcast frame. [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.

Brian Ector: Thank you, Jamie. Good morning, ladies and gentlemen and thank you for joining us to discuss our third quarter 2024 financial and operating results. Today, I am joined by Eric Greager, our President and Chief Executive Officer Chad Kalmakoff, our Chief Financial Officer and Chad Lundberg, our Chief Operating Officer who is joining us today from our Houston office. While listening, please keep in mind that some of our remarks will contain 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 following our prepared remarks, we will be taking questions from the analysts. In addition, if you are listening in today via the webcast, you’ll have the opportunity to submit an online question, and time permitting we will strive to answer your question. With that, I would now like to turn the call over to Eric.

Eric Greager: Thanks, Brian. Good morning, everyone, and welcome to our third quarter 2024 conference call. We’re pleased with our third quarter results, which demonstrate continued solid operational performance as well as our commitment to generating meaningful free cash flow and the delivery of strong shareholder returns. During the third quarter, we generated CAD 220 million of free cash flow, returned CAD 101 million to shareholders through the share buyback program and quarterly dividend, and reduced net debt by 5%. Over the last five quarters, we’ve returned almost CAD 500 million to shareholders. We have bought back 75 million common shares for CAD 387 million, representing approximately 9% of our shares outstanding, and paid total dividends of CAD 92 million.

We have also reduced our net debt by 12% over the last four quarters. We increased production per share by 10% in Q3 2024 compared to Q3 2023 with production averaging more than 154,000 BOE per day, 86% oil and NGLs. Our crude oil production comprised of light oil, condensate, and heavy oil increased 2% from Q3 ‘23 to average over 112,000 barrels per day. I’d like to turn the call over to Chad Kalmakoff to discuss our financial results.

Chad Kalmakoff: Thanks, Eric. We remain committed to a disciplined returns-based capital allocation philosophy to drive increased per share returns. Eric touched on our free cash flow and shareholder returns. As a reminder, under our balanced shareholder return framework, we allocated approximately 50% of free cash flow to the balance sheet and 50% to shareholder returns, which includes our share buybacks and our quarterly dividend. In Q3 adjusted funds flow was 538 million or CAD 0.68 per share and we generated net income of CAD 185 million or CAD 0.23 per share. In addition to the operationally strong quarter, which delivered excellent financial results, we benefited from approximately 22 million of one-time items including insurance claim proceeds related to the 2023 Alberta wildfires and adjustments with respect to previously paid royalties.

Continuing to reduce debt remains a priority and we made significant progress during the quarter. Our net debt at September 30th was 2.5 billion, down 5% from June 30th, 2024. Our total debt, which excludes working capital at September 30th, 2024 was CAD 2.3 billion, and we maintained our leverage ratio with a total debt to EBITDA of 1.0 times based on the trailing 12 months EBITDA. We’ve updated our 2024 expense guidance, which reflects year-to-date results and our expectations for the fourth quarter. Notably, we are guiding to lower royalty dates, lower royalty rates, lower G&A, and lower current income taxes, all which impact, all of which – all which positively impact our adjusted fund flow and free cash flow for the year. Operating and transportation expenses are trending in line with full year guidance.

Now I’ll turn the call over to Chad Lundberg to discuss our operating results.

Chad Lundberg: Well, thanks Chad. We had a successful quarter and I want to spend some time highlighting our Q3 operations. In the Eagle Ford, production averaged approximately 90,000 BOE per day, 82% oil and NGL, up from 87,000 BOE per day in Q3 2023. During the third quarter, we brought on stream 17 operated wells. Our development program is largely focused on the black and volatile oil windows of our acreage where we typically generate 30-day peak crude oil rates of 700 to 800 barrels per day or 900 to 1,100 BOE per day with average lateral lengths of 9,000 to 9,500 feet. Based on well placement in Q3, lateral lengths were down slightly with overall results trending in line on a length-normalized basis. Due to efficient drilling and completion activities year to date, we have realized an 8% improvement in operated drilling and completion costs per completed lateral foot over 2023.

In our Canadian light oil business unit, we have made substantial strides in advancing our understanding of the Pembina Duvernay with production averaging 7,600 BOE per day, 83% oil and NGLs, up from 4,800 BOE per day a year ago. Last quarter, we highlighted our first pad, three wells, that delivered strong production results. Our second pad, four wells, was brought on stream in August and hit two has resulted in strong production, with 3 of the 4 wells generating average 30-day peak rates of 842 barrels per day of crude oil and 1,125 BOE per day per well. Based on public data, 3 of these 4 wells ranked in the top 15 for new oil wells in the province of Alberta for the month of September. The Pembina Duvernay is in its demonstration stage of development.

This year, the team made some notable enhancements to the program and I’m excited by the results. Through a combination of drilling, completion, and facility design optimization, our average 30-day peak production rates improved by 40% as compared to 2023 well results with only a 4% increase in lateral length. The balance of our portfolio continues to perform well, including our Viking light oil and heavy oil business. Peavine continued to outperform expectations. We had a successful Blue Scott exploration well on a recently acquired 66-section land block in Peace River, and we continued our development across the broader Manville Group in Lloydminster, including progressing our Waseca development. With that, I will turn the call back to Eric for his closing remarks.

Eric Greager: Thanks, Chad. We’re pleased with the strength of our Q3 operating and financial results, our commitment to shareholder returns and the notable reduction in our debt. We anticipate full year 2024 production of approximately 153,000 BOE per day with exploration and development expenditures of approximately CAD 1.25 billion both trending to the midpoint of our original guidance. For 2025, we expect to release our budget in early December. I want to reiterate our commitment to prioritizing free cash flow. And in the current commodity price environment, this means moderating our growth profile and delivering stable, levelized crude oil production. We’re well-capitalized and remain focused on disciplined capital application. And now, Jamie, we’re ready to open the call for questions.

Operator: Ladies and gentlemen, at this time, we will now begin the question-and-answer session [Operator Instructions] To submit the question in writing, you may use the form at the lower right session of the webcast frame. [Operator Instructions] Our first question today comes from Greg Pardy from RBC Capital Markets. Please go ahead with your question.

Justin Ho: Great, thanks. It’s Justin Ho on the line for Greg Pardy. Thanks very much for taking my question. So really just one question from me. Just wondering if you could frame out your drilling plans and expectations for your Duvernay asset, maybe through the balance of this year and into next year. Obviously cognizant that you’re still working through the budgeting process.

Eric Greager: Yeah, good morning, Justin. Thanks for the question. We are continuing this demonstration stage in the next year and we’ve been very systematic in our framework. Next year is, provided continued performance improvements and success, which we fully expect. We intend to budget a seven to nine-well program. So that could be a three well and a four well, two four wells, or three — three wells, but somewhere in that range, and that’ll continue to help us demonstrate not only stimulation design improvements, spacing optimization, and drive continued performance improvement as we continue to both gather in data to inform our models and our statistics, but also continue to improve those energy delivery systems into the reservoir.

So, again, kind of seven to nine for 2025, and,again, on continued progress, we would likely move, we would likely start ramping up toward full development in 2026 and that could be nine to 12, ‘27, could be 12 to 15. What we’d like to do is continue to push that ramp forward. A lot of this is price-dependent, of course, as we mentioned in our moderating growth comment. But the bottom line is we expect this play to deliver very strong economics, very strong capital efficiencies. And we want to get it to the kind of one rig levelized pace of development that will keep a frac crew working pretty much round the calendar, but for the coldest periods of the winter and we think that will allow us to really extract operational efficiencies out of our acreage.

Let me just stop there, Justin, and see if you’ve got a follow up.

Justin Ho: No, that’s perfect, Eric. Thanks very much. That was the only question I had, so appreciate it.

Eric Greager: Thank you.

Operator: [Operator Instructions] And we do have an additional question. This is from Amir Arif from ATB Capital. Please go ahead with your question.

Amir Arif: Oh, hi, good morning, guys. Just wanted to get a little bit more color on that Peace River, Oak of Blue Sky well. Could you just give us a little more color on where you got the 66 sections of land? Was that just Crown Lands or was it through an acquisition? And just the initial rates and color on that first well.

Eric Greager: Yes. Good morning, Amir. So actually in our investor deck, you’ll see a map toward the back in the asset area. You’ll see a kind of a blocky green polygon in our Peace River slide. I’m just thinking in my mind’s eye here because I don’t have it in front of me. But it’s kind of in the 10 or 11 o’clock position a big green block. It’s about 66 net sections. So it’s a fairly large physical block. It was a private farm in and so we saw prospectivity based on our experience in the blue sky and we’ve drilled two development wells, well I’d call them exploratory at this point and we’ve had success in terms of what we have seen and the performance of the laterals. So we feel pretty good about this. I’d point out, which I haven’t been shy about in 4 years we’ve made 4 discoveries in our heavy oil business starting with Peavine and the Clearwater.

This is the fourth in 4 years. And in what I would say notionally 3 or 4 different horizons in different parts of heavy oil. So it’s the gift that keeps on giving and considering the large position we’ve got about 600,000 net acres, we expect to continue this successful effort around the acreage and just continuing to replace inventory and production with new reserves and new discoveries but that’s it on the Peace River Blue Sky. We sometimes call it West Cadotte because it’s in that general area. But you’ll see it on the Peace River map in our deck.

Operator: And ladies and gentlemen, with that we’ll be concluding the audio question and answer session. I’d like to turn the floor back over to Brian Ector for any questions received online.

Brian Ector: Thanks, Jamie. Yes, we do have a couple of questions coming in online to the webcast. So, thank you for that. Eric, the first question comes back to the shareholder return framework that Chad spoke to being balanced. And just a question around the use of excess cash and preference for reducing debt or buying back shares?

Eric Greager: Yes, so, Brian, thank you, and thanks for the question through the portal. We really do like the balanced framework until we get down to the CAD 1.5 billion absolute level and I would point out that the share buybacks in the last 5 quarters we have purchased or repurchased 75 million shares which was mentioned in our earlier prepared remarks and that represents 25% of the shares issued for the Ranger transaction. So in 5 quarters, we purchased repurchased 25% of the share issuance. We’re proud of that and we think this balanced framework between debt reduction, a modest fixed base dividend and share repurchases is a good one and we intend to stick with it.

Brian Ector: Thanks, Eric. A question around the depth of the inventory across our portfolio, we’ve spoken to 10 to 12 years, but maybe can you just elaborate a little bit how that makes sense in a 5 year planning and even beyond a five year planning purposes, Eric.

Eric Greager: You bet. So, so we do a full depletion plan every year. We take every asset all the way out to the end of its life, last acre, last well, last barrel of recoverable reserves but obviously we don’t publish all of that information. It’s for internal planning purposes. We feel really good about this 10 to 12-year inventory and we feel like we can continue to deliver high-quality results over one-year, three-year, five-year, and 10-year horizons with the inventory we’ve got. We’re pretty balanced at that 10 to 12 years across most of our positions whether that’s the Eagle Ford operated non-op or our Viking or our heavy oil, the variety of heavy oil positions we have. But I’ll point out that in particular, the Duvernay, not only, have we really made progress in the last couple of years through the new stimulation design frameworks and statistics and machine learning tools but it also represents something like 25 years at the current pace of development and that’s a lot of value trapped out in time and this is the primary reason, not only the performance and the quality but its proximity to market and the fact that by pulling it forward, we can create a lot of shareholder value and again, strong economics, strong capital efficiencies, and we’d like to pull that long inventory forward in time to line up better with the balance of our portfolio.

And these things, as long as I’m talking about a portfolio, Brian, I just want to mention these things work in a complementary fashion. So, our Eagle Ford with the strong realized pricing Gulf Coast markets, that generates the sort of cash engine, the cash flow engine for the balance of our portfolio and to fuel not only the excess cash flow that we’re able to buy back shares and pay down debt with, but also capitalizing the Duvernay program in this next leg of our strategic growth. And so as one, as we pull one leg forward and create value through the Duvernay organically we’re able to fund that organically through our Gulf Coast operations. And then alongside that, we have this really powerful stabilizer running at 40,000 to 45,000 barrels a day, continuing to replace its own inventory and barrel production and maintain kind of strong heavy oil performance and economics and so it’s a pretty interesting portfolio balance for a company our size.

Let me just stop there, Brian, and we’ll take the next question.

Brian Ector: Sure. So a couple questions of come in under a hedging strategy. Can you maybe just elaborate on what our current hedging strategy looks like, Eric, and, maybe provide an update on where Q4 fits in 2025 as well?

Eric Greage: Yeah. I’m going to pitch this one over to Kalmakoff, Chad, take it away.

Chad Kalmakoff: Sure. Yeah. Our hedging strategy really hasn’t changed. We’re fairly focused on the crude oil hedging, and I think we like to think about it as more of an insurance policy than really certainty of cash flow. So what we look to do is purchase a, put floor on the oil volume. So we always look for a CAD 60 floor, and it kind of works nicely into the asset level. So at the CAD 60 floor, that’s kind of getting closer to cash flow breakeven, or kind of where the marginal assets have rates return around at 50%. So we bought this put floor, around CAD 60 and really we sell calls to fund that put floor kind of as high as we can. So historically through 2024, we’ve kind of been close to 60 by the time of the mid-nineties.

We are now hedged to 2025. Early part of 2025 we’re 60 by high 80s and then the latter part of 2025 would be kind of 60 by 80 callers. So on the crude basis, we’re fairly hedged up here for the remainder of 2024 just over 40%. Into 2025, we’re hedged around the 45% level on the crude oil volumes again kind of CAD 60.4 by clearing calls on the top end of that structure. But and generally speaking I think on the total volume hedge we kind of look to the balance sheet. So while we’re in this period of kind of one times or north of one times debt to EBITDA we look to be kind of 40% to 50% hedge. And then as we reduce our leverage over time we’ll probably reduce the hedging that we have along with it. We have also hedged a favorable gas volumes.

It’s not that impactful to the overall revenue streams that we have. Most of our gas we do have is associated gas with the oil but we do have approximately 50% of our hedged gas exposure next year in NYMEX on collar structures around CAD 3.10 to CAD 4.25.

Eric Greager: Yeah, and the contango price structure just kind of gives you that opportunity for free, right. It’s able to go out longer and get higher prices and just protect that gas that will be produced as an associated product. I would point to Slide 10 in our deck in the event that folks don’t know where that’s at. You can use that as a companion to the comments Kalmakoff just made.

Brian Ector: I’ll stick with you for one more question around the target mix of our credit facilities, the US dollar terms, Canadian credit facilities that target CAD 1.5 billion you maybe just elaborate on that target mix of what we’d like to see?

Chad Kalmakoff: Sure. Thanks, Brian. So in our current structure we obviously have more high yield debt outstanding than the total debt target. So as we go forward, I think we’ll have a little bit of a mix of the structure although I think we’d be heavily weighted to the term debt structure that we have in place. We do like the term debt. It is flexible. The market is deep. Ideally, we kind of keep tuition issuances outstanding. So over time we probably reduce a little bit of a term debt outstanding and we may have a little bit on the revolving facilities but we tend to have less on the revolving facilities go forward and more to the term debt.

Brian Ector: Eric, two questions operationally for you. One in Canada due to the weak gas prices do we have any volume shut in? And two in the US, Eagle Ford refracs, what are your thoughts on that? So two-part question for you.

Eric Greager: Yeah, let me take the first part first. We really don’t have much in the way of intentional gas production period and because of that, because virtually all of our gas is associated gas with our oil and oil prices have remained relatively strong compared to gas prices in the markets we sell into, we’ve continued on production and so I think that’s a pretty straightforward answer. And the low gas prices, whether you’re looking at AECO or NYMEX, they’re really the impact is pretty de minimis to us considering how much of our production is dominated by oil price and oil revenues and natural gas liquids and that’s particularly true when it comes to AECO where the prices are, let’s just say, particularly weak and have been.

It just has very, very little revenue impact on us. And on NYMEX, we mentioned earlier the opportunity to put in the simple two way collar structure to protect that over time. On the reef fracs, we really like the program and the proof of concept with the Modena really put wind in the sails and helped encourage us around just our ability not only to pick the right wells and pick the right attributes that will lead to success, but successfully execute. I never had any doubt, but it helped put kind of real results behind the concept as a proof of concept. It’s always going to be a supplement to our primary development campaign. So, I guess I would just want to caution people don’t expect more than say, three to six per year and don’t expect us to guide openly to when they’re going to happen or what capital is associated with them.

We’re just going to use those as kind of supplemental bits along the way to take advantage of the opportunity when efficiencies — when industrial efficiencies present themselves.

Brian Ector: I’m going to touch on one more question as we wrap things up here, Eric. And this one relates to the overall capital efficiencies of our business. Can you maybe speak to what you see as our capital efficiencies and second part, opportunities to drive further efficiencies in the business of what we’re seeing?

Eric Greager: You bet. So I’m going to, this is going to be a two part answer I’m going to try to answer at a higher level, and then I want Chad Lundberg to come in and maybe add some commentary around specific examples of things we’ve had success on 2024. I’m going to start at a pretty high-level. One of the things I’m really excited about with regard to our Pembina Duvernay is, this is a highly capitally efficient project and getting to our levelized one-rig pace of development sooner is going to bring those efficiencies forward sooner. And as we continue to increase the portion of our total production that is represented by our Pembina Duvernay, it offsets or replaces poorer capital efficiencies elsewhere in the portfolio.

And if it turns out we’re growing the lion’s share of the growth will be represented by our growth out of our Duvernay. So if there’s any growth in our portfolio, it’s going to be coming from our Duvernay and those are top within our portfolio, top quartile capital efficiencies and across the board kind of top quartile, top third efficiencies across the whole of North America. They’re just really, really strong. These are million BOE type curves. We’re drilling notionally 10,000-foot laterals and we can extend those and we have experience drilling longer laterals and successfully stimulating and bringing the sales longer laterals than that and so we feel really good about this, pulling this leg of inventory forward, and we have the potential to hold the line or even potentially improve our capital efficiencies over time as the Duvernay takes a larger and larger share of the total production in our mix.

I’m very proud of the assets we’ve got and the capital efficiencies, but there’s always room to get better and we’re always looking for opportunities to squeeze efficiencies and costs out of the system. With that, I’m going to hand it off. Lundberg, why don’t you take it away with some specifics around examples.

Chad Lundberg: Okay, thanks. I would start with the biggest gains that we get is on the capital efficiency side and just from efficiencies in our operations. That efficiency comes, we believe partnering with really, really good service companies that would share consistent and common beliefs to ours on not only the work front and driving out stronger results, but on the safety side, that’s a big pillar of our successes is focusing on safety and by doing that, we believe kind of all things fall in suit. We also have a very strong cross-border interaction where we can really just focus on the different technical programs, tweak the technical programs, but most importantly, learn from one side of the border to the other. And so if you think about the headline numbers in Eagle Ford, where we’re talking about an 8% cost reduction this year, if you think about the Duvernay, where we’ve seen a 10% reduction on our drilling costs, A lot of those are very consistent, whether it’s minimizing vibrations on downhole tools so that we can have extended motor lives or even just the long tenure of our drilling rigs and one of the biggest efficiency gains we saw in the Duvernay this year was deploying the same drilling company for a second year.

In the off time, they were able to make the rig fully walking, did upgrades to it with respect to the shaker systems and different things that just, like I said, allowed us to drive these efficiencies out of the equation. Yeah, I’d just leave it at that. Efficiency comes from long-term relations. It comes from level of programs. It comes from focusing on safety and it comes from a great cross-border interaction and just pressing our teams to do better.

Brian Ector: Great. Thanks, Chad. And I think we are now reaching 30 minutes and the end of our call for today. I would like to thank everyone for participating. For those who submitted questions via the webcast, if your question was not addressed we will certainly strive to reach out to you. And with that, thank you operator, and thanks to everyone for participating in our third quarter conference call. Have a great day.

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