Peyto Exploration & Development Corp. ($PEY)

Good day, and thank you for standing by. Welcome to the Peyto's Fourth Quarter 2025 Financial Results Conference Call. [Operator Instructions]. Please advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, JP Lachance, President and CEO. Please go ahead.

Thanks, Marvin. Good morning, folks, and thanks for joining Peyto's Fourth Quarter and Full Year 2025 Conference Call. Before we begin, I'd like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory set forth in the company's news release issued yesterday. Here in the room with me, I have Riley Frame, our Chief Operating Officer; Tavis Carlson, our CFO; Lee Curran, our VP of Drilling and Completions; Todd Burdick, our VP of Production; Mike Collens, our VP of Marketing; Derick Czember, our VP of Land and Business Development; Crissy Rafoss, our VP of Finance; and Mike Rees, our VP of Geoscience. Before we discuss the quarter, on behalf of the management group, as always, I'd like to thank the entire Peyto team, both the folks in the field and in the office for their contributions to yet another strong year. And to be clear, they're the people that make Peyto what it is. If I could sum up what the team accomplished in 2025 in one sentence, I'd say the company responsibly invested shareholder capital in 2025, which grew the business while returning a healthy dividend to shareholders and paying down a significant chunk of debt. Getting into the specifics, the company spent $475 million, which grew annual production and PDP reserves by 7% or 4% per share and PDP reserves value by 2% per share, and that's despite the lower price decks that were used by the evaluators. We paid dividends of $265 million or $1.32 per share and reduced net debt by $171 million or 13%. That's a pretty big accomplishment considering AECO prices averaged $1.76 per GJ last year. So let's start with the fourth quarter. We kept 5 rigs running through the quarter right up until the Christmas break, then shut down to give those folks some time off to be with family during the holidays and recharge. We drilled some great wells in late Q3 and throughout Q4 as our program focused more on the Notikewin and the flares, which tend to be the most productive species in our portfolio. Naturally, production ramped up in December, which averaged 145,000 BOEs per day. It's timed nicely for the increase in gas prices at both AECO and our multiple downstream markets. We spent $142 million in the quarter, bringing our total up to $475 million for the year, which landed in the middle of our capital guidance range and matched well with our exit production of 145,000 BOEs per day. This equates to an exit to exit capital efficiency of $10,000 per BOE. So essentially, we delivered on what we said we were going to do at the beginning of the year. If we dive into operations a little more, we spent 81% of that $475 million on drilling 82 gross or 78.4 net wells with -- while most of the rest of that capital was spent on facilities and strategic pipelines, including a big field compressor in our core Sundance property. The mixture of wells we drilled last year are essentially delivering the same average productive outcomes as 2024 at same costs, which doesn't sound like much, but if you go back a couple of years, that's a 25% improvement year-over-year and a function of our acquisition of the Repsol assets that we purchased in late 2023. Some of the new plays we drilled last year include follow-ups to Bluesky, Viking and a prolific flare channel we discovered a couple of years ago. And of course, we drill a lot of non -- a lot of great Notikewin wells, too. But importantly, we continue to expand our drilling inventory by finding and developing new ideas that were not previously on our reserve books. In fact, 34 of the 82 wells we drilled last year were not recognized, and that's simply because the Deep Basin is endowed with a great stack of opportunities that we continue to unlock in and around our 1.1 million net acres of land. On the production operations side, as always, our efforts continued on reducing costs and optimizing our vast 1.5 Bcf a day of gas processing capacity and gathering infrastructure. In areas where we haven't been as active drilling like Brazeau, we had -- I think we just had one rig running there most of last year. We've been looking at to bring third-party production into the plant to increase throughput and improve field netbacks. For that, we built an important pipeline in Q1 of 2025 and are actively seeking more opportunities like that. Turning to Q4 financials. The end of year ramp-up in corporate production resulted in a fourth quarter average of 140,800 BOEs per day. That's up 6% over the same period last year or 3% per share. That drove funds from operations up Q4 over Q4 by 23% to $245 million. To get there, we received all-in revenues of $4.71 per Mcfe and after subtracting cash costs of $1.23 per Mcfe resulted in a cash netback of $3.47 per Mcfe before we include performance-based compensation and cash taxes. That's a 60% improvement over Q4 of 2024. We also generated one of the highest quarterly earnings in our history at just under $126 million or $0.61 per diluted share. Of course, both our hedging and marketing diversification played a role -- a big role as AECO monthly gas sold at $2.22 for the quarter or about $2.55 an Mcf when you factor in our heat content. Our hedge gains added $0.76 per Mcf, and our diversification to other markets added another $0.70 per Mcf of value to our realized gas price. So clearly, our marketing efforts played an important role in the quarter. Looking at the full year, we generated $860 million of funds from operations, an increase of 21% over 2024, which more than funded the capital program and dividend, as I mentioned at the beginning. Total cash costs, excluding cash taxes, averaged $1.29 per Mcfe. And if you remove royalties of $0.16 to get what Peyto controls, it equates to $1.13 per Mcfe, and that's an $0.11 improvement over 2024. I think as you may recall that in the January '26 monthly report, we set ourselves a goal to reduce controllable costs further by another $0.10 in 2026. And as we reported, these low cash costs and strong revenues for the year generated a field level netback of $3.61 an Mcfe or an all-in cash netback of $2.93 per Mcfe when you include cash taxes, G&A and interest expense. Our reserve additions last year were one of the strongest in our 27-year history and essentially a repeat of 2024. If you haven't already, I'd encourage you to read the March monthly letter, which -- where we highlight some features from that reserve release that was issued on February 19. But essentially strong well performance and prudent capital spending by the entire Peyto team drove PDP FD&A costs down to $0.94 an Mcfe. That's the lowest in the Canadian oil and gas producers. And when you combine our industry-leading low cash costs and high netbacks, it yields an after-tax cash netback recycle ratio of 3.1x, meaning we turned -- essentially meaning we turned $1 into $3, and that's pretty good for a natural gas producer last year. As we've always emphasized, margins matter most. And last year, Peyto put up an impressive 72% annual operating margin and a 31% annual profit margin. Of course, these margins generate the promise to sustain dividends to return to shareholders, grow the company and protect our balance sheet. Turning to marketing. We continue to reap the benefits of our marketing diversification and hedging program. We've added a table in the press release to show what the 2 programs have achieved relative to AECO pricing over the last 8 quarters. For the full year 2025, that premium to AECO on a volume average basis is about 88% or $1.80 per Mcf over AECO prices. Looking forward at our hedge book, it secured a total of $880 million in revenues for '26 and another $355 million for 2027 as it stands currently, you can expect us to continue our systematic hedging over the next 6 gas seasons and stay within the guardrails of our policy. And as we've always said, we hope our hedges are out of the money when we get there because that means that we're seeing better natural gas prices. In this case, it will be over $4 an Mcf in 2026 or $3.50 in 2027. The gas that we have left floating for 2026 is pointed at U.S. price markets, which allowed us to capture a premium on the daily market this past winter and continues to trade above AECO when -- even after you factor in the cost to get there. Okay. That was a lot of numbers and about the past. But to be clear, we think demonstrating the past execution is an indicator of future performance. So why don't we turn to the future. Looking forward to our plans for 2026. It's already been quite a volatile market for commodities, fueled by weather and, of course, world events. Our plan remains to spend $450 million to $500 million, drilling 70 to 80 net wells, the same as last year and the same as the year before. We expect to use 4 to 5 rigs to accomplish this. We'll slow down for breakup and then start up after the wet season. Current plan will be to run 4 rigs for most of the summer with an option to ramp back up to 5 later in the year depending on prices. Remember, we're all -- we are well protected through the summer with about 70% of our gas volumes fixed at prices just under $4 with very little exposure to spot AECO. Rest of our production is pointed to downstream markets, so we'll be watching them closely. At this point, we project a 4-rig program after breakup gets us pretty close to the midpoint of capital guidance, and we can adjust from there depending on where the business environment goes. We remain constructive on natural gas with the continued LNG build-out in Canada and the U.S. and increased demand from local markets like power for data centers. Clearly, recent world events remind us the need for energy, and we believe Canada can play an important role in providing a reliable, secure and affordable supply of oil and gas to these global markets. To that end, we continue to advocate for egress and local demand projects so that Canada -- Canadian oil and gas can support the global demand for energy and our Canadian economy. In the meantime, we expect commodities will be volatile, but thanks to our prudent business strategy to keep the cost that we control as low as possible while protecting the revenues with our commodity marketing strategy, we expect to continue to deliver stable long-term returns to our shareholders and increase the value of the company. So I imagine there's a few questions. So maybe, Marvin, I'll open up the phone lines. If there's some questions in the queue, we can get to.

[Operator Instructions] And our first question comes from the line of Travis Wood of NBCC.

JP, I think earlier in the year, you mentioned some ability to tie in and build a small pipeline to tie in some third-party gas. I think that was into the Brazeau plant. You reiterated that with year-end. In the same breath, you kind of flagged ample spare capacity, close to 40% of spare capacity across the kind of corporate processing plants. So do you think there's an opportunity to continue to expand to run third-party processing across other parts of the portfolio? Or how are you thinking about that from a kind of another revenue stream?

Yes. Maybe I'll get Todd to elaborate further on that. But generally speaking, of course, we have a lot of space in our plants. And so -- and getting utilization up is a key to reducing overall costs or increasing income in this case, if we were to add third parties to it. So in the areas that we operate, it's -- we're pretty much the dominant operator in a lot of the places where we own facilities. So just bringing in third parties, they either have their own facilities or we're just not active in the areas that we operate. But to the extent that we have opportunities like that, and a good example was the Brazeau area where we've added some volumes there last year, and we'll continue to search for more. I think in total, Todd, if I'm not wrong, we have about $20 million or so of third-party gas going through some of our facilities. And then there's some gas that comes in naturally with partner gas as well to our facilities. But do you want to elaborate further on our plans to look at new opportunities there?

Yes, sure. So our JV group has been very active really over the last couple of years working on some of these deals. So they obviously got the one into Brazeau, and they're looking to get some more in there. There's -- when you ask about getting gas into plants that have capacity, we have a pretty robust drilling program this year, development program. So that's going to likely fill up or keep full some of our gas plants in the Sundance area. We're going to build -- we've got some pipeline projects that will allow us to effectively protect our base, but move gas into the Oldman, Oldman North area, Nosehill, move gas -- free gas up in the Swanson area for new development. So things will, as the year goes on, get a little tight in some of the areas in Sundance. But obviously, the Edson plant the JV group is working to get some gas into their Brazeau, as I mentioned. So they're always mindful in talking to us as far as where we're going to have capacity on where they should be focusing their efforts. And I think they'll continue to do that as this year unfolds.

Okay. And then last question, just in terms of the reserve report, you had flagged 34 locations in terms of percentage. I don't think that's too different in terms of what wasn't captured in this year's reserve report versus past years. But could you talk about the formations or fields within those 34 locations that were pushed into possibly next year's numbers?

Yes. So to be clear, what we're highlighting there is the fact that we don't just drill the wells that are on our reserve books that we have other opportunities that we can drill and will drill throughout any given year. And I think historically, that's been around 32% of the well count has been, at least over the last 10 years has been on new lands. And that was my point earlier in my opening remarks is that we continue to chase things. Maybe I'll get Mike to elaborate a little bit more, Mike Rees to elaborate a little bit more around why is that or what are we seeing and give you a little more color on that, if you like. So Mike, maybe you can...

A broader question might be why don't just drill our locations and where does this unbooked inventory come from? I would say just one of Peyto's guiding principles here is to constantly high grade our drilling inventory. Our drill schedule to maximize returns, ultimately were driven by economics. So on book locations present the opportunity to optimize species mix and allow us to be nimble in reacting to things like changing market conditions. But to drill down a little bit more on where these on book come from. I guess the first point I'd make is we can't book all of our potential locations nor any other oil and gas entity. We have to follow strict rules with the reserves evaluators around what locations can be classified as booked -- and typically, those that are not getting booked would be viewed as perhaps a little bit more risky. We may not have nearby analog for that particular play, for instance. But we do continue to refine our geological mapping as new data becomes available, which can lead to identifying previously unknown trends. And I would point to what JP mentioned a little bit earlier back in 2024, we drilled -- tested a new channel trend in Falher right in the heart of Sundance, where we drilled many wells before. And that initial test was quite successful, and we've been very aggressive in following that up since. Another point is that we continue to add every year to our land position through land sales and deals with other companies. And those lands, obviously, we believe are prospective, they have locations on them. Otherwise, we wouldn't have done those deals or pick those lands up that wouldn't have been reflected on prior year's books. We also watch closely what our competitors are doing in and near our core areas. Perhaps they may unlock a new zone that we can then capitalize on our own lands. But again, that's something that wouldn't be reflected on our prior year's books. So yes, I mean, we're willing to test new zones when and where it makes sense. I guess the final point, but an important point that I would make is that the evolution of drilling and completion technology, coupled with Peyto's leading cost structure can make previously marginal zones more competitive for capital within Peyto and ultimately make some of those zones in some of the areas quite economic. So that's [indiscernible] to Lee and his team. So I guess all of this taken together really demonstrates that we don't rest on our laurels, and we're always driving to maximize shareholder value regardless of whether locations are -- sought your outlook.

And one follow-up just to that question. Would -- of those 34 locations and for competitive reasons, this can just be a yes or no, but unless you want to provide more color. But any new formations that weren't part of the active 2025 program within those 34 in terms of maybe not new zones within the stack, but new formations more broadly?

I think the short answer to that is we drilled these 34 wells that we drilled last year were across all the formations that we typically have and all species in fact. So it wasn't just one particular species. So we see value as well as new plays within zone. So yes, we won't elaborate on details because there might be follow-ups in program for '26.

Our next question comes from the line of Chris Thompson of Canadian Imperial Bank of Commerce.

I want to start with your capital plans, JP, you talked about the option to ramp later in the year to a fifth rate depending on pricing. Could you elaborate on sort of what price signal you'd be looking for to do that?

Yes. I mean that's a loaded question in a way because we're looking at the futures, too, not just one price. I think for us, it's going to be where do we see prices, but also where is the business environment in general as far as cost, too. For example, if oil prices were to stay high, for example, and gas prices were to continue to fall away now you've got maybe potentially increasing your supply costs or your cost for services, right, because the activity ramps up just the same. So it's a combination of several things. That's why I mentioned we business environment, not necessarily just price. But for us, price, we'd like to see prices at least where they are. I think a slight improvement, of course, to go to the high end of our guidance would -- I think we'd want to see prices increase from here. And if prices were to fall further, then we'd likely guide towards the lower end of our guidance as simple as that.

Okay. Got it. And then I guess, yes, on the low-end side of the discussion, I mean some of your gas peers have indicated a bit of caution around growth and capital spending given the forward strip. And I recognize you guys are well hedged for 2026, but there's still -- I guess there's still other considerations you might take. So how are you thinking about activity levels and a downside type of growth rate?

Well, activity levels would obviously drop. We would moderate the 4 rigs that we have that we would continue to run to go to the low end of our guidance. I think that of our capital guidance, I don't see us spending less than that based on the fact that we -- so that means $450 million, less than that based on the fact that we have a strong position, not only for '26, but also even into '27. And so I don't see us changing the plan that much. We'll cautiously watch it. We'll be -- we'll react to prices this summer to the extent that we have anything exposed to AECO and we don't like the price, then we will moderate production and we'll regulate production accordingly. But I think our capital plans will remain in that range, $450 million to $500 million.

Okay. Sure. And then maybe just a question for Mike Collens on the gas markets here. We've seen LNG prices move a lot higher given the conflict in the Middle East, but North American markets have really yet to respond. So just wondering if we can get your views on how these markets might evolve through the summer, especially if the conflict is attractive.

Sorry, Chris, to clarify, you're talking about gas or oil prices?

On the gas side.

Yes. I don't -- we can provide a view of that. I mean, to us, we're sort of agnostic around price because we have 70% of our prices that are hedged for the summer. I mean -- but maybe, Mike, if you want to provide some color around how you see things going forward here, but...

Sure. Thanks for the question, Chris. When we look at opportunities to add to the diversification or even the hedge book for that matter, you can appreciate that there's a lot of discipline that goes into that decision-making and tenor that would be required to put that position on. So when we're evaluating opportunities, whether it's LNG or other diversification opportunities, it's got a long time horizon, and it has to be accretive to not only our position, but also to alternative markets can get us. So does the LNG market look attractive today to have those deals on? Sure. But most deals that we're evaluating in that space have a start date of '27 or '28 or even later if they're project related. So we have a much longer time horizon in how we evaluate decisions for the business. I hope that answers your question. There's always opportunities that come even as far as the cold shot in the wintertime that was experienced. You would have asked the question 3 months ago, we'd like to have some of that on right now, sure. But we're constantly evaluating opportunities that what does that risk profile look like 5, 10, maybe even 15 years down the road.

Got it. Yes. Okay. Fair enough. I mean where the Peyto model really shines is being able to layer in some of these price dislocations that happen when they happen. And so I was probing at sort of are you starting to see some of those opportunities just given the move we've seen in global benchmarks, like from what I could tell, the forward strip hasn't really improved for NYMEX and that much. And so question is like when do those opportunities start really showing up on Peyto's hedge book, if at all?

Sure. Like I said, there's a lot of discipline that goes into the decision-making to make sure that we're adding good deals that prop the book up higher than where we're currently at. There's a lot of unknowns in the LNG space as well. I'm sure there's a lot of excitement around the short-term price bump, obviously, what's happening in global events. But if you consider that the price of oil might well spur more drilling in liquids-rich areas like the Permian, then you can appreciate that maybe the curve in NYMEX might not have a lot of upside to it as it relates to the LNG spike in the price of crude in the short term. So we're constantly exploring the opportunities. We're constantly looking for prudent risk that would benefit the book and not just in the next 12 months, but how do we layer these on 5, 10, 15 years. And there's a lot of work that goes into it. And I'm sure you can appreciate how we built the book up to this point. It's taken quite a bit of time, and we're starting to bear the fruits from that past 5 years. But -- so yes, sure, it might provide some excitement in the short term, but we have to really see it play out in the long term to have it make sense and put it on.

Yes. Fair enough. And then I'll just -- one more follow-up for me, just on domestic markets like specifically the AECO market. What do you guys see from a supply-demand picture kind of going forward here? Like data centers have been obviously very topical. Do you think that's a real opportunity that's going to help us see some strength in the AECO market because like LNG hasn't really done that just yet, and hopefully, it will, but what other demand catalysts could be beneficial for the Alberta market?

No, clearly, I think, Chris, we see the power demand being a catalyst in the future. The timing of that is some projects that are already underway and there are other projects that will come later, and we feel like we're in the right place for that. So I don't -- in the longer term, again, this is -- like Mike said, we're looking past -- longer term, we think we're in the right space here that there will be some -- certainly some incremental demand that comes from power generation requirements for data centers or what have you. Oil prices go up, there's increased demand for gas for oil sands. There's lots of places where we can see potential for gas prices to go up as LNG projects get approved and we get reconnected with the market. So we're still very positive on the AECO market. It's just -- we have to manage the short-term prices, and we think we do that very well.

[Operator Instructions] Our next question comes from the line of Michael Harvey of RBC.

So just had a question as it relates to your views on M&A. You've obviously had some very good results from the Repsol deal. There's probably going to be more assets available in the Deep Basin. So I guess just a couple of things. Maybe you could just walk us through just quickly your process on evaluating the strategic fit of things you might add, just kind of basic stuff in terms of how Peyto thinks about it. And then the Repsol deal was pretty much hand in glove in terms of the map sheet. But -- just wondering how you would think about adding other assets in addition to the hand in glove stuff that kind of might be noncore? Or is it basically just kind of looking for interlocking fit on everything? Just any broad thoughts appreciate it.

Yes. Thanks for the question, Mike. When we approach M&A, we've always approached it the same way, whether they be big or small opportunities. Repsol was a bigger one, obviously. But we're always looking for own and control. If we look at the attributes of any kind of deal that we're going to consider one, it's going to have the right attributes for us and those attributes include things like owning and controlling the infrastructure or having the ability to move it into our own. So it may not be -- may not necessarily be its own infrastructure as long as it has its own infrastructure in some way or we can operate that way. We want to see some synergies with respect to an ability to reduce -- ideally reduce the cost structure of the assets so that we can add value that way. So there may not be priced into the value of those assets. So I'm talking about reducing operating costs and things like that, not just synergies like G&A reductions, I'm talking about real synergies with respect to the costs on the operating side of the business. It has to have a quantity of upside that's suitable to the production if we're buying production that it has. So quality and quantity are important, and that quality and quantity should be able to compete with what we have today, right? The other element is important is having egress capabilities, right, and that ability to be able to get whatever we might want to grow into the market. So obviously, to sell it and to be able to grow it from there. So like we're not looking at opportunities just for the sake of opportunities to get bigger. We don't want to pollute the business. And so we've been fairly consistent on this. Obviously, Repsol was a really good fit. And so to the extent that there are other opportunities like that out there, and they don't have to necessarily be just in and around us that can be beyond that, too. We'll continue to look for plays that have the attributes that we prefer. We had a really good success with Repsol. We -- if we're going to do another one like that, and Peyto is not known to be an acquirer per se, so it's going to have the same sort of value upside in the way we're going to look at it. So we'll be careful, and we'll be picky, and we'll find the right opportunity. We have a team dedicated to this. Derick's team is dedicated to looking for new opportunities. And so we'll continue to do that.

Got it. And then on the staffing front, how big do you think Peyto could get in terms of adding production volume, acreage, et cetera, and still maintain the kind of industry-leading cost structure? Is there a size you think about? Or is there -- or do you just think you could kind of scale up effectively under any production scenario?

That's a good question. Did you read the monthly report that came out last year? We probably -- we talked a bit about that, right? And I think I actually have a -- we actually put a plot out that sort of projected where we think we could get to and still maintain sort of under a magic number that was put out there. It's important. Culture and the size of the organization is really important to us. So that is a factor when we think about growing, and it's something on all of our minds that people around this table understand that. And I think it was Peter Drucker that said, culture eats strategy for breakfast, right? And I think that's on our minds as far as getting bigger for the sake of getting bigger, another big reason. So just because it might make sense, there may be some value in being a bigger organization for cost of capital or for -- being investment grade to allow us to get a lower cost for our debt, although right now, it's pretty low already, almost the lowest in the industry. So for -- especially for our size. So size, I don't know, like there was magical numbers out there, but maintaining a flat sort of structure and having people that are accountable and empowered to do their job is really important. That's what we talked about. If you want to come back to some of the monthly reports, suggested, I think that if you think the magic number is 150 people, but we're a long way from that right now at just under 100 folks in the office here to include the consulting staff. So that's -- there's lots of room for us to grow, but we have to remain disciplined in that and the team here understands that, that we need to continue to maintain the culture that we have, we're focused and we're focused on costs and managing our business without doing anything extra that we don't need to do. So we've got lots of room to grow. We're only 100 people here at the high end. So...

I'm showing no further questions at this time. I'll now turn it back to JP for closing remarks.

Okay. Thanks very much, Marvin. I just want to remind folks that our AGM is coming up, and that AGM is scheduled for May -- I think it's May 21. It's going to be in our office or in our building here at plus 15 level in Calgary. It's an in-person meeting. Also, I want to remind folks, we referenced the monthly report a few times there in this call and discussion point. If you -- we write this report to give folks a sense of relevance -- write some topic that's relevant to our business, and it provides an update of our monthly production and our capital spending based on the field estimates. These monthly updates of our operations on operations not only demonstrates our transparency, but it also provides some confidence that we have real-time accuracy of our numbers. And so there should be no surprises when we get to the quarter end. If you want to subscribe to that, you can go on our website, it's under the Investors tab, I encourage you to do that. So... Okay. Well, thanks, folks, for tuning in. See you next quarter.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.