Baytex Energy Corp (BTE) 2024 Q2 法說會逐字稿

Thank you for standing by the conference operator, and welcome to the Baytex Energy Corp second quarter 2024 financial and operational results conference call. As a reminder, all participants are in listen-only mode and the conference is being recorded. (Operator Instructions)

I would now like to turn the conference over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

Thank you, Brenda. Good morning, ladies and gentlemen and thank you for joining us to discuss our second 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.

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 analysts. In addition, if you're sitting in today's today via the webcast, you will have the opportunity to submit an online question and time permitting. We will strive to answer your questions.

With that, I would now like to turn the call over to Eric.

Thanks, Brian. Good morning, everyone, and welcome to our second quarter 2024 conference call. In the second quarter, we delivered strong results with higher production, disciplined capital spending and meaningful free cash flow. Importantly, and consistent with our full year plan, we returned $97 million to shareholders through our share buyback program and quarterly dividends.

As we continue to execute our plans for 2024, our free cash flow is expected to strengthen in the second half of the year, allowing for increased shareholder returns and debt reduction. We increased production per share by 23% in Q2 24 compared to Q2 23, with production averaging more than 154,000 BOE per day, 85% oil and NGLs.

Our crude oil production comprised of light oil, condensate and heavy oil, increased 4% from Q1 24 to average over 110,000 barrels per day. We are executing our 2024 development plan with a tightened production guidance range of 152,000 to 154,000 BOE per day at the midpoint. We continue to target 153,000 BOE per day for the year.

Our 2024 exploration and development expenditures. Guidance is unchanged at $1.2 million to $1.3 billion, and we expect to generate approximately $700 million of free cash flow in 2024, 75% weighted to the second half of the year. We intend to allocate 50% of free cash flow to the balance sheet and 50% to shareholder returns, which includes a combination of share buybacks and a quarterly dividend.

Now I'll turn the call over to Chad Kalmakoff, to discuss our financial results.

Thanks Eric. We remain committed to a disciplined returns-based capital allocation philosophy to drive increased per-share returns. In Q2, adjusted funds flow was $533 million, or $0.65 per share 38% higher than $0.47 per share in Q2 2023, and we generated net income of $104 million or $0.13 per share.

During the second quarter, we generated $181 million of free cash flow. And as Eric mentioned, we returned $97 million to shareholders. We repurchased 16.4 million common shares for $79 million and paid a quarterly cash dividend of $18 million or $0.225 per share.

During the last 12 months, we have returned $378 million to shareholders, repurchasing $57.5 million common shares for $304 million, representing 6.7% of our shares outstanding and paying total dividends of $74 million or $0.09 per share.

On June 26, 2024, we renewed our normal course issuer bid with the Toronto Stock Exchange, which allows us to purchase up to 70 million common shares during the 12 month period ending July first, 2025. As of yesterday, we are proud to say we have repurchased 7.2% of our shares outstanding dating back to June 30, of last year.

We touched on this last quarter, so I won't get into the detail today, but I do think it's important to note that we have extended our debt maturities, the term structure of our long-term notes and liquidity on our credit facilities have been greatly improved and positions us well to run our business through the commodity price cycles.

Our total debt at June 30, was $2.5 billion, which represents a total debt to EBITDA ratio of 1.1 times. Our total debt is largely unchanged from year end as in addition to free cash flow generated year-to-date, our total debt also reflects the strengthening US dollar relative to the Canadian dollar, which increases the balance in our US denominated notes, the call premium and issuance costs on our notes offering and the credit facility extension and strategic land acquisitions we did in the first half of 2024.

Continuing to strengthen our balance sheet remains a priority. And based on our forecast free cash flow and shareholder return profile, we expect a reduction in total debt in the second half of 2024.

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

Thanks Chad the strong free cash flow that our business generates is a testament to the efficiency of our exploration and development program and our stable production profile. I'm now pleased to speak to our Q2 operations and highlights the significant efforts of our team during the second quarter. Exploration and development expenditures totaled $340 million and we brought 40 net wells on Steam.

In the Eagle Ford, we continue to deliver strong results across our acreage. We generated production of over 90,000 BOE per day, 82% oil and NGL and brought 11 operated Lower Eagle Ford wells onstream that were largely focused on the black oil window.

Some of you will recall that during the second quarter we hosted analysts and investors for a tour of our Eagle Ford operation. One of the site visits was our Pluto pad that was in the midst of completion operations. This pad was brought onstream during the quarter and is now one of our strongest performing oil-weighted pad to date with three wells generating an average 30-day peak initial production rate of over 1,150 barrels per day of crude oil.

Due to the efficient drilling and completion activity, In the first half of 2024, we realized an 8% improvement in operated drilling and completions costs per completed lateral foot over 2023. In our Canadian light oil business unit Clipper three well pad from our 2024 Duvernay program, West brought onstream in May and generated an average 30-day peak initial production rate of 890 barrels of crude oil and 350 BOE per day per well. These initial results are consistent with our expectations. The second four well pad is expected to be onstream in August.

In our Viking light oil and across all our heavy oil operation. Second quarter activity is typically lower due to spring breakup following spring breakup, our heavy oil development program has ramped up with four rigs running across our Peavine, Peace River and Lloydminster region and two rigs running in the Viking.

Peavine continued to outperform expectations, with production averaging almost 20,000 barrels per day, up 13% from Q1 2024. We brought four wells onstream at Peavine that generated an average 30-day peak initial production rate of 760 barrels per day per well.

With that, I will turn the call back to Eric for his closing remarks.

Thanks, Chad. I want to take a moment and circle back to our shareholder return framework. As many of you have noticed, we have gradually stepped up our buyback program and have now reached a consistent buyback level currently set at $1.4 million per trading day.

We believe this is a prudent approach that allows us to meet our commitment to return 50% of free cash flow to shareholders in the form of share buybacks, quarterly dividends and improving per share metrics.

I am pleased with the strength of our Q2 operating and financial results as we execute our plans for the second half of 2024, our free cash flow is expected to strengthen allowing for increased shareholder returns and debt reduction.

And now, operator, we are ready to open the call for questions.

(Operator Instructions) Greg Pardy, RBC Capital Markets.

Yes. Thanks. Good morning and thanks for the further rundown.

So I've got a couple of questions that maybe just on the financial side, could you give us a sense as to what that trajectory looks like in terms of CapEx and production in the second half? And then just the potential, particularly, I think, for debt reduction and buybacks, please?

Yes. Hey, Greg, it's yes, yes, I'll take those first, because I don't think I'll remember more than two questions on CapEx and project production trajectory. I'll answer that on CapEx on we're still pointing to the midpoint of CapEx and that's implied by the $1.2 million to $1.3 billion CapEx guidance range.

It should be weighted more toward Q3 into Q4 just in terms of that weighting and trajectory. And in terms of production performance, we're still pointing to the midpoint of full year annualized. So that's 153,000 BOE per day, which would imply a pretty level second half of the year kind of at the production level we're at right now. And that, of course, backing into levelized operations across our footprint allows us to really generate more efficient levelized operations.

As far as the debt paydown trajectory, I'm going to pitch it over to Chad Kalmakoff and have him give a quick answer on that and then please jump back in with if you've got another question.

Sure. Thanks.

Thanks, Greg. Yes so, we had free cash flow, a couple hundred million in the first half of the year, we're looking at another $500 million in the back half of the year. If enough that we should have a couple of them really hitting the balance sheet or paying down debt. So looks like you see debt paydown obviously accelerate here in the back half of the year compared to the first half.

Obviously, we had the bond refinancing done here in Q2 and some Bs and the discounts associated with that, which would have impacted our ability to pay down debt this quarter. But at the same time, extending our debt maturities are pretty important to us. Again, the lower coupon there will be impactful in the years to come.

Okay. Thanks for that. And maybe just completely shifting gears maybe into the Duvernay, could you frame maybe your learnings and results thus far as you as you as you work through your seven-well program? And then is there anything to say maybe about efficiencies or where costs are kind of coming out on that because it's a pretty important program, I guess, going forward?

You bet, Greg. Again, it's Eric. Gregor here. So I'm going to give it kind of one minute at a high level. And I'm a pitch at the lumber for the details on efficiency gains, our 7-well program, a 3-well pad and a 4-well pad, a 3-well pad came on in May. The results have been in line with our expectations and our model and strong and so 90% liquids, 65% oil, 1,350 BOE a day on average. We also pushed length on one of the laterals out to 4,000 meters which feels pretty good.

So lots of good, I think operational learnings along the way, strong well performance. We should be bringing in the four-well pad on in August, and we'll have more to talk about there. Lundberg over to you.?

Yes. Thanks Greg. To really answer the question, you need to really look broad efficiencies and look in basic now as we have Eagle Ford and the Duvernay and evolution and learning (technical difficulty) are swapping back and forth with each other. They're calibrating large machine learning and all data sets to better inform what we view on (technical difficulty)

If I think about the Duvernay itself results, we've got drill results and now a 5% -- reduction in overall drill days. That's translated into a 10% reduction in cost, completion results are still being calculated.

I think you are (technical difficulty) 10% reduction in overall drill and increased in effective something hours per well. If I say just one -- finish answering your question one layer deeper. The model would inform us year-over-year, the changes we've been making around the water side in Duvernay to increasing its water intensities.

And then like I said, we have a balanced conversation across the border. If you think about across the border is more of a cluster spacing, stage spacing sand. So continuous evolution replacements to play off each other. We're seeing positive results in both, and I do believe that there's more to come.

Okay, terrific. Thanks very much.

Jeremy McCrea, BMO Capital Markets.

Hi guys. Thanks. Just I got a couple questions here, too. So first one, did you guys do anything different with those Eagle Ford wells that came on at some of the best rates you've done. I'm just curious if that's some of the rates that we could expect going forward?

And then the second part here is some of the efficiencies you noted in your press release. Is any of that built into your guidance and capital costs? And then with some of the results today, particularly in the Duvernay. Does it make you look to shift capital around 2025?

Yes, hi, Jeremy. It's Eric here. Again, I'm going to maybe take one minute off the top and then pitch it to lumber for a little bit more around efficiency changes, particularly in the Eagle Ford.

So if we look back, I just want to put some kind of historical context on this H2 2023, the well performance on the crude oil side was about 700 barrels per day. Now those were tended to be gassier. So the BOEs were way up. But let me just focus on oil for the moment.

H2 2023, 700 barrels a day average across trying to 22 wells, then we advance to the first half of 2024 and in 23-wells on that same crude oil average daily on the IP30 went up from 700 to 835 barrels per day on average. And then if you compress that to the second half, the first half of the year, that is Q2 the eight wells we turned in had an average IP30 of crude oil only of $871.

So to your point that just that just reinforces the on the oil side of this mix, which is where all the value comes from. We've gone consistently higher and in Q2 8-wells averaging 88%. And so that all feels pretty strong, continuing to be either in the top quartile or the very top of the second quartile in terms of crude oil performance among a strong cohort of performers in the Eagle Ford.

In terms of strength and efficiencies around the Eagle Ford, specifically, Chad, why don't you take that? And then I'll come back to the allocation question.

Well, thanks, Jeremy. I would answer this way. Similar to Greg, we're continually trying to inform through our machine learning through our model. There is all what we're going to do next. Specifically when we think about efficiency and capital efficiency discussion, not just production, not just capital, but combining the two together on the capital side, we've seen an 8% reduction in the Eagle Ford. This is from little things throughout the program. And again, we translate the learnings across the Duvernay.

Geo-steering, so drilling in a tighter target stage spacing that I alluded to in specific material path, we did improve the stage spacing that we think is helping the overall result all the way down to how we handle frac valves and how we handle hookups and the frac, the wells. And so all that to say, there's a bunch of little things that are really driving out costs.

On the production side. Again, I would point to the intensity. It all comes back to the overall, where are the area that we can effectively stimulate the rock and to do that, we know in these unconventional that comes back to your intensity in the fracture stimulation itself. So that's what we're really keen on specific to the Pluto pad. That's where we were going.

In terms of efficiency based in Ford -- we tried to do our best to think about that in that budget cycle. I think that the only thing I would end with is continuous improvement. And I think there's more to come. We always seem to prove that year-over-year.

Okay, Jeremy. I'm going to come back to the to the allocation question. Here we are in kind of late July. It's a little bit early in the and a planning cycle for me to even have a really strong crystal-clear view on allocation. But what we would say is we're always focused on allocating our capital, our toward the highest returning opportunities.

And so we remain encouraged by the quality of our Duvernay assets and the rate at which on our machine learning models are advancing, gives us a lot of confidence and encouragement around our continued development in our Duvernay play. And of course, that includes the extension, the land extension that we executed on in Q1.

So you should expect us to continue to grow that both in terms of it's on total production mix in the total portfolio up on with increasing up the rate at which we allocate capital to it, given the advancement in our models. But it's too early to kind of guide more specifically than that.

Okay. Thanks Eric.

Thanks, Jeremy.

Amir Arif, ATB Capital.

Thanks. Good morning, guys. Just had a few quick operational questions for you. Just first on the Duvernay, are you doing anything different on the second four-well pad? Or is this more just derisk and delineate the two sides of what you're setting on?

Yes. So the second four-well pad is going to have many of the same features in terms of cluster and stage architecture and you know, lengths and how we land in terms of the stack where we land in terms of the lithology and resistivity marks along the way and how we steer to stay in the highest quality reservoir and all the same kind of operational tips and tricks of the trade in terms of cementing and casing and drilling. So all of that's done.

But because these models are learning constantly and the four well pad is a little bit behind in time of the three-well pad. It will have a few nuanced hydraulics chemistries. It's fluid and architecture changes in it that the model is suggesting. And so again, you don't waste an opportunity, not a moment, not a day to test. You have new applications and techniques.

And so on. It will have all the same advances that were built into our drilling casing and cementing program because it came at the same time. But in terms of stimulation, it's a little further on. And so the model is a little bit more informed. The models advanced literally every well that's drilled in the whole play, but very, very specifically relevancy weighted to our own data. So they advance fast on our own data.

Is there anything Chad, you'd like to add to that in terms of advancements in the four well pad versus a three well pad.

Just looking at bound versus unbound well spacing. It's another opportunity for us. That's it.

Okay. I appreciate the color. And then just on to the PBT line or the fee level, production continues to get better or better than the 15,000 that we were thinking about a while ago, is 20,000 a number to think about as a sustainable rate? Or is there potential can even get that a little higher than those levels on a field-level production?

It's a great question, Amir. And you know, I was always trying to be, I think, prudent in my guidance given what, and don't know about conventional reservoirs over time.

As I think I've said before to you and publicly to others on the wells, just continue to surprise to the upside as we moved our pads to the south, our in late 2023 and into 2024. The pads came on stronger. They stayed stronger for longer. The pads and the team continue to surprise to the upside and we're facing today a 20,000 barrel a day. Our play here in Q2.

I think that it can probably hold us for a little while, but I'm not going to I'm not going to suggest a new normal that that's meaningfully above 15,000. But what I would say is maybe Peavine could exit the year around 17,000 and that probably it means that it heads toward 15,000 over the longer arc of time. But again, it's well staying stronger for longer and continue to surprise to the upside that could be a while out.

So I feel bad for having said 12,000 to 15,000 for so long, but I am going to say over the long arc of time, you know, we should continue to be in these kind of mid-teen and I'll continue to say 15,000 until we know a whole lot more about the aerial extent, but it feels really, really good. And just the whole thing is performing very well.

Yes, that helps. And then just on the aerial extent part of it there, Eric, the I know you move to the south from the core. Are there any plans to move to the northeast area or is that more of a '25, '26 event?

Yes. Over time, we will, Amir. It's we will continue to move eastward and to the north and east. But it will take some time. One of the things we've mentioned is that we remain very conscious of our social license to operate with the Peavine Metis. And it's not unique to sort of legal obligations as much as it is. We like to do what we say we're going to do.

But also around capital, it's a very efficient use of capital to keep these developments nice and tight. And so over time, we're going to move eastward and then Northeastward. But the tighter we keep it geographically, the more we're able to maintain high capital efficiency on the sort of pipelines and driving rights of the way we've built and locations we've built.

And that will just increase the efficiency of the investment over time, but we will, over time, move eastward in Northeastward.

Makes sense. And then just finally shifting to the Eagle Ford. Eric, I know as you move to the black oil it's got lower overall rates with better oil cuts of the total weight time significantly different, but I believe it's also shallower.

Can you just give us a sense of what the well cost differences are from the volatile oil windows. You stepped entity, black oil window, and then also just second half plans, do you plan to stay in the black oil window? Or are you going to move in around your acreage position?

Yes. So, one of the reasons we move around is partly to take advantage of gathering system room. So, that is to say, you build a CDP at some point in time and then you fill it. But as the wells that justified that central production facility decline off, they leave available capacity and that available capacity through the CDP and through the gas gathering and oil gathering system is effectively free.

And so one way to manage capital efficiency on the facilities part of the business is to move around and what I call knife into that available capacity. And so one of the reasons we move around is, A, to continue to inform our models and keep them very current in terms of stimulation designs and optimizing that. But B, to also ensure that we are making maximum use of the available system space.

So, in terms of capital, it's all very much in line with our expectations. Our AFEs have come into expectation. Our capital budget is coming into expectation and everything is running in line.

And so, as I mentioned earlier, in terms of our current budget reiteration, it all feels quite good and we're going to continue to move around a bit to ensure that we take maximum advantage of available space. But the wells are going to continue to perform well according to the stimulation designs.

And I would say with confidence, almost no matter where we go, we'll be able to get the best out of the rock using the machine learning models.

Can you just quantify the well cost difference? I think it's 10.5 on average across the Eagle Ford. Is it different in the black oil window?

Yes. Sorry, Amir, I didn't I didn't come back round to that. It tends to get a little bit less in the black oil window because you're dealing with a little bit lower pressure. And so one of the reasons why it's less gassy as because it's less thermally mature and thermal maturation time and temperature and burial depth and all of those things drive gas production.

And so because it's not as deep and it's not as highly pressured or thermally mature. You tend to get a little bit of a break on things like Cat tolerance and the depth of casing shoes and those sorts of things. Having said that, you tend to have to drive a more intense stimulation into lower thermal maturation rock. And so the model compensates for all of these things, I'd say generally in line, but maybe a little bit lighter on a kind of a cost per foot basis.

Chad, you want to just reinforce that or just.

Well, yes. So, the only other significant difference is they are generally cooler reservoir temperatures, so as you get deeper in (technical difficulty) gassier portion or gas condensate area, we run higher temperature but, in some cases, it pushes us into different bottom hole assembly. Just in terms of quantifying, we're in the $0.5 million range to drill these black oil wells versus in the gas.

That's the difference between the two.

That's right.

Okay, appreciate the insights. Thanks.

This concludes the question-and-answer session from the phone lines. I'd like to turn the conference back over to Brian Ector for any questions received online.

All right. Thanks, operator. And we have had a number of questions come in. I feel that we've addressed the majority of the operational questions that have come in on the webcast, Lee, as we've discussed, the efficiency across the portfolio and our guidance being unchanged.

The one common question coming in, Eric, does relate to the share price performance and any reaction to the results today. What is your takeaway or thoughts on the market reaction today?

Yes. Thanks, Brian. Well, look, I'm disappointed on any time the share price trades down, but this is a this is a beat quarter. We came in above consensus estimates on production up above consensus estimates on AFF per share. We continue to take out more shares every day. We've levelized our share repurchase plan so that it now accomplishes dollar-cost averaging, which should over time drive the lowest possible volume-weighted average price for those for that use of free cash flow.

And what I would say is, we can't control the share price. What we control is the business, our allocation of capital, capital efficiency, cost of capital and to a lesser degree, not directly. And the free cash flow that we generate. If the share price goes down, we'll simply buy back more shares. And so eventually the shares we take out of the system and we cancel that math will continue to drive better and better in intrinsic per share metrics.

As I mentioned earlier in my prepared remarks, over the past four quarters, we've increased our production per share by 23% in one year 23% increase in production per share. And that's both higher production on a on a flat share number of shares, but also, we're taking out shares and that will continue.

So I like a bargain as much as the next guy, and we're going to keep buying back our shares at a discount. And eventually that's going to be irresistible. But that math really works when you're generating strong and resilient cash flows and free cash flow, Brian, that math works to our advantage.

Okay. Thanks Eric. And this is a question that came in from an investor. It's a statement as much as it is a question. I think it relates to the performance today and the statement is that the market is inaccurately focused on lower sequential BOE per day rate in the Eagle Ford on loss on the market was the higher oil cuts and lower costs in the Eagle Ford pressing -- more oil for well in Eagle Ford during the second quarter to get more getting oilier sequentially to the positive trend that drives higher cash flow generation.

Eric, I know we talked about Eagle Ford at lot, but any final comments on getting oilier or the oil rates and the performance in the Eagle Ford?

No, I think that statement is spot on, Brian. What I would do is I would simply reiterate eight wells, 88%. And in the Duvernay, the three-well pad is 90% liquids. And so, we are an oil company. Our Q2 results were 85% weighted two liquids, high-value liquids, and we will continue to focus on that.

And yes, in terms of our free cash flow yield, when the share price goes lower relative to our free cash flow generation, that just means it punches at an ever stronger level in terms of these impacts to per-share metrics. So I like I like the mechanism, I don't like the share price, but we can take advantage of it. And we will continue to buy back shares according to our NCIB and keep that VWAP as low as possible.

And the other comment coming in on the financial side does relate to the debt repayment and the timing addressed it in our prepared remarks. Chad addressed it any comments on the importance of continuing to deliver across the Board?

Well, it's extremely important on and, you know, I know folks are frustrated and have pointed to that our total debt to EBITDA is 0.1 times, and that is a that is a strong position to be in today. In terms of the total debt to cash generative capacity of the business and that will get better over time.

But we thought it was more important within the first half of the year to take advantage of these record tight spreads on to two prepare a more defensive posture with regard to our long-term debt structure. And so our goal through reducing the coupon and extending the term of our long-term debt made a lot of sense to us. And then that allowed us to push our credit facility out another two years.

And so the term debt structure within our business is very strong and very defensive. And you have to do that when you can because you can't control the timing, but these are record type spreads for high-yield energy and we took advantage of it.

And we think it's the right thing to do. And we think when our debt paydown does begin to happen in Q3 and Q4 and continue from there, folks will begin to take advantage of and realize the benefit of all of this.

Thanks Eric. At a higher level, portfolio-wise, any thoughts on asset sales, dispositions, the overall portfolio where you see the business going over the next two to three years?

Yes, I can't really comment specifically on asset sales or dispositions. What I would say is every asset in our portfolio is investable. Every asset is being invested in and that all feels pretty good.

But we're always looking at this through each planning cycle and making sure that if there are assets that we're allocating our capital to the highest returning assets possible running all of our assets within the bands of maximum operational efficiency. And if there are assets we cannot invest in, then those are the assets that moved to sale against a retention value expectation.

Okay. Eric, we're coming up on our time limit here, but just one last question because it's in the news a fair bit of late. Loss and wildfires again across Alberta, do you see any impact to our operations so far this year with respect to the wildfires?

Yes, it's absolutely heartbreaking to read about Jasper and anyone who's lost their homes or their businesses, it's absolutely heartbreaking to see and to witness. We've had no impacts and have no wildfires within close proximity to our operations.

So, we're sort of better off this year than we were last year in terms of proximity of fires. We remain on high alert. We're always looking and watching and reading and lending a hand to our peers and our friends, any place that we can. So, that's about all I would say, Brian, on that.

Sure. Great. Thanks Eric. So, thanks everyone. As we reach the end of today's call, I would just like to thank everyone for participating. For those who submitted questions via the webcast, if your question was not addressed, please reach out to our Investor inbox and we will be sure to respond.

With that, thank you, operator and thanks to everyone for participating in our second quarter conference call. Have a great day.

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