Peyto Exploration & Development Aktie

Good day, and thank you for standing by. Welcome to the Peyto's First Quarter 2026 Financial Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to turn the call over to JP Lachance, President and CEO. Please go ahead.

Thanks, Lisa. Good morning, folks, and thanks for joining Peyto's First Quarter 2026 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, Tavis Carlson, Lee Curran, Todd Burdick, Mike Collens, Derick Czember and Crissy Rafoss and Mike Rees to answer any questions. Before we begin the quarter, on behalf of the management group, as always, I'd like to thank the entire Peyto team that's both in the office here and in the field for their contributions to a record-breaking quarter.

Overall, there's lots going on in the world during the quarter, some of which continues today, of course. But we manage through the chaos with a focus on execution like we always do. The record-breaking quarter I mentioned relates to production, funds from operations and earnings, both on an absolute basis, but most importantly, on a per share basis. We spent $150 million in the quarter and still managed to pay down another $89 million of debt, which brings our total debt reduction since the Repsol acquisition in October '23 down by $275 million.

Going forward, Peyto is bigger, stronger and financially fitter than ever, which means we feel it's time to give a little more back to shareholders with an increase to the dividend. So let's dive into operations first. We're off to a good start this year. We ran 5 rigs in the quarter across all our core areas. We drilled 23 wells in the quarter over a variety of species from the Cardium down to the Bluesky, investing $121 million on well-related costs less drilling, completing, equipping and tying in.

The average performance of these wells are tracking closely with the last 2 years' outcomes, and we're particularly pleased with the latest Cardium drills down in Brazeau. We applied the same drilling and completion strategy that worked so well last year in the Chambers area. And this is where we drill a little deeper in the -- what we call the bioturbated zone to increase drilling rates, greater penetration and then complete the longer horizontals with more stages.

The gas rates are better, but most importantly, so are the liquids that come from the wellhead, and that's increased -- that's up to about 500, 600 barrels a day of initial production rates. On the production operations side, we had a busy -- we were busy adding additional strategic pipelines in the field to assist with the development program and to optimize production. And as always, invest in better in our plants with equipment and maintenance to extend the life and increase reliability.

All told, we invested $26 million in these projects. The balance of the capital spend in Q1 was used to capture another 41 gross sections of land through direct purchases and crown sales and average attractive rate cost of about $200 an acre. This boosts our drilling inventory and some of this we plan to drill later in the year. Subsequent to the quarter, we have redirected about 75 million cubic feet a day of gas to a third party to increase C3+ recovery. So that's propane, butane and pentanes plus. That adds up to an incremental 1,000 to 1,500 barrels a day at a time when liquids pricing is stronger. This has not come with an increase to operating costs, so it improves our overall netbacks as well. And maybe I'll get Todd to expand upon this a little bit later in the call.

Switching to Q1 financials. The continuation of the fifth rig and consistent well results allowed us to grow production to an all-time high of 148,000 BOEs a day and an average of 147,000 BOEs a day for the quarter. That's up 10% over the same period last year or 7% per share. Cash costs in Q1 totaled $1.28 per Mcfe, which was down 10% from the same period last year due to lower interest costs, which would be attributed to less debt and lower rates. We also had lower royalties and slightly lower operating costs down $0.01 per Mcfe.

Despite having the lowest cash cost of all the producers, Peyto still expects to lower controllable costs. When I say controllable, I'm referring to operating transport interest and G&A by 10% this year over last year's annual average. That equates to about $0.10 an Mcfe. Flipping to revenue, another strong quarter where our realized price for gas was $4.69 an Mcf or 73% higher than the AECO monthly average of $2.71 per Mcf, which that's adjusted for our average heat content of the gas.

The major contributors for capturing that superior price came from a $0.37 hedge gain and $1.61 per Mcf of diversification value. And that meaningful diversification value mainly comes from our purposeful daily exposure to markets in Chicago, Ventura, Dawn, Parkway and Emerson during those cold winter weather events this past winter. So that combination of low cost and great pricing allowed us to put up some very strong cash flow numbers for the quarter, and we had record funds from operations of $293 million or $1.41 a share. Record earnings of $171 million or $0.82 a share, generated an impressive operating margin of 77% and I think the highest profit margin in the last 10 years of 39%.

And if you look back over the last few years, the consistency of these margins is what matters most, and it's what gives us confidence in our business model that pays the dividends to our shareholders, grows the company and protects the balance sheet. This strong cash flow led to more debt repayment in the quarter, as I mentioned earlier, $89 million and allowed us to hit our soft -- I'll call it our soft leverage target of 1x debt to trailing 12-month EBITDA earlier than we thought. We're now comfortable delivering more of that free cash flow back to investors and have announced a modest increase to the dividend of $0.01 per share per month or a 9% increase. With this increase, we still expect to retire more debt by year-end at current strip prices, and we'll continue to revisit that dividend level as the year matures, keeping a close eye on future prices in the business environment, of course.

Our low costs, our strong hedge position where we've secured $715 million for the balance of this year, that's Q2 to Q4. Another $510 million has been secured so far for '27, combined with that diversification to the multiple markets outside of AECO, it provides us with the confidence in the sustainability of the dividend going forward. Despite the volatility in commodity prices, Peyto remains committed to investing between $450 million to $500 million this year, drilling 70 to 80 wells, net wells. We've slowed down activity for breakup.

I think we're down to 2 rigs now, and we'll start up as weather permits, and we plan to run between 4 and 5 for the rest of the year. Modified our drilling program slightly going forward to shift towards more liquid-rich species like the Cardium and the Falher. There's even some oil rich in certain areas that have a little higher liquid content. And remember, we're well protected through the summer with about 70% of our gas volumes fixed at prices just under $4 an Mcf with very little exposure to spot AECO. The rest of our production is pointed to downstream markets. So we'll be watching them closely, and we'll manage gas volumes accordingly.

We remain constructive for natural gas with the continued LNG build-out in Canada and the U.S. and the increased demand from local markets like power for data centers. Recent world events remind us the need for security -- sorry, for secure and reliable energy. We know that the gas price market can be particularly volatile. So our mechanistic disciplined hedging will continue. Peyto strategy remains the same, focus on execution, control the things that we can control and that's costs while mitigating the risks on the commodities with both hedging and market diversification. We think that's a winning recipe that provides returns to our shareholders.

So before we get to questions online, there's a couple that have come in overnight, one particularly on the deal we did with a third party. I think Todd, I've often said this that we have an allergy to third parties processing. So maybe you can expand upon the reasons why we did that we're sending out $75 million to a third party.

Yes, sure. So obviously, we've mentioned the nice uplift of 1,000 to 1,500 barrels of propane, butane, C5+. With that deal, any liquid ethane has returned back to us as a gas. So there's no ethane in the deal, we can say that. And along with that, like was mentioned, the structure means that we don't see any increase in operating costs, which is great. So along with the, I guess, liquid -- more liquid increased portion of our drilling program this year and the incremental liquid recoveries, we should see about at least a 1% increase in our overall liquid content.

Yes. I guess it's safe to say this is obviously a confidential agreement, so we can't too much, but thanks for the color. Yes. Thanks for the color.

Okay. Lisa, why don't we open up to questions from the phone line, if there is any, please.

Okay. Not a problem. [Operator Instructions] The first question today will be coming from the line of Michael Harvey of RBC.

Yes. So just a couple of questions for me. It looks like you hit your longest measured depths in the history of the company this past quarter, helping to drive those better rates you mentioned. Is there more to do in terms of that number, making it even higher? Or have you kind of come close to the point where you're maximizing recovery and balancing with CapEx?

And the second one, just on the dividend. Maybe just remind us your methodology there. I think in the past, Darren had always talked about dividends being sourced from earnings, which would imply some more upside, but I think you also have to balance that with your payout and just the lumpiness of the business. So maybe just remind us kind of how you see that in terms of what -- how folks can think about that number going forward?

Maybe I'll answer the Divvy question first, and then I'll turn it over to Riley on the well length question. Certainly, our profits are from our earnings. And we do believe in paying the dividend comes from that. However, we do also want to be mindful of the balance sheet, and we want to make sure whatever we do is sustainable going forward. So I mentioned there at the outset, we have -- we expect to pay at least at current strip prices, expect to reduce debt further here this year.

So there's obviously more room should we want to balance this with 100% payout. So there's more room there, but we'll be careful to -- with future strip and make sure that whatever we do is going to be sustainable. The nice part about all this is that we have secured a fair bit of, like I said earlier, of revenue for next year already. And anything out in '28 is actually well above our sort of minimum price. So as we -- as I talked about our mechanistic hedging program will start to take that gas down. So it gives us confidence in the level. So we're going to watch where prices go from here. So there's room to move, as I mentioned at the beginning here in the opening comments. So -- but we'll be careful as we move forward to make sure that's sustainable.

Maybe I'll turn another question over to Riley around well length. I think you were asking just can we see continued increases in well length or what's the expectation? So I'll turn it over to you.

Yes. So I mean, I think we'll continue to try and optimize on well length as we roll forward here. But I think a lot of the material gains over the last sort of 5 years have probably been made in that regard. Our land base and our geologic situation is probably more of a constraining factor at this point as far as how long we go with all of our wells. But obviously, we see the benefit on performance. We see the benefit on cost in doing so.

And obviously, that has an impact on our per unit metrics. So we'll continue to optimize that going forward. But I would say that we won't see the gains that we've seen over sort of the last several years going forward.

[Operator Instructions] Next question will be coming from the line of Chris Thompson of CIBC.

So just wanted to probe for a little bit more color on the NGL processing agreement there. So this third party is receiving no operating cost change from you guys. So what are they receiving from this?

We're not recovering ethane. So one would think that, that may be an opportunity for them to gain some value because we mentioned that we just -- we're not getting ethane, maybe recovered, but we're not taking that. We're getting that back in the gas phase. So that would be one way. Perhaps I don't know. You have to ask them. And I'm sorry, I can't tell you who they are.

Okay. No problem. But just wanted to clarify, so 1,000, 1,500 barrels a day against our full year number is just shy of 1% of your production. So are we increasing total production? Are we increasing just the mix and hence, the realized price? Like maybe help us understand the modeling implications on that side.

I would just increase your liquid content by 1% is probably the safe thing to do. And as we move through this year, we'll get better clarity on what exactly that number is. We'll also get better clarity on the impact of the Cardium species program that we talked about shifting towards a little bit more. So if you're modeling this, I would say, increase -- just increase your percent of liquids by 1%, as Todd mentioned.

Okay. Maybe just one comment you made in the press release looking at running 4 or 5 rigs for the balance of the year. My read on that was it was fairly noncommittal as to whether it would be 4 or 5. So I was just wondering, JP, if you could expand on how you're thinking about that.

So we're done 2 right now, of course, to break up, and then we'll bring rigs back when appropriate here as weather things dry up out there. And 4 rigs probably puts us to the midpoint of our guidance. 5 rigs probably pushes us to the higher end of our guidance. So if prices improve from where they are, and we see that especially the future prices, not just current prices. So we would look to maybe expand that program to 5 rigs later on the year. We might actually add a fifth rig later in the year, just to set us up for Q1 next year. So that's why there's a range there.

Okay, got you. Are you seeing -- just especially for that fifth rig that is not necessarily part of your steady program, are you seeing much service cost inflation on the rig side?

I'll ask Lee to answer that one. It's right now and things are relatively fresh. I don't know what you want to add something to that, Lee?

Sure. Yes. No, we're not really seeing anything material. Of course, fuel surcharges is in everybody's bottom line from oil and gas operations right to the household. But remember, we are the lowest capital cost producer in the Deep Basin. So we control what we can control. We are seeing fuel surcharges, but we're seeing a reduction in a number of things, including at this point, OCTG, tubulars, rig rates. It's more than offsetting the fuel surcharges we're experiencing.

Direct fuel purchases are about 3% of our capital cost. So a surcharge on that isn't really material to the overall program. Of course, it's going to slip into everything else we do, but a little premature to say. And at this point, what's manifesting in terms of efficiency gains is more than offsetting we're seeing associated with spot. [indiscernible]

I guess on the flip side of that, we would be seeing incremental revenue, obviously, if fuel prices stay high, that means oil is high, that means we'll be seeing more revenue. So that will be -- that also will help to more than offset any increase in costs.

Todd, do you want to add anything on the op side of it?

Sure. For sure. There's a portion of the OpEx that's exposed to this inflation, probably 15% to 20%, things like chemicals, trucking, obviously, as Lee mentioned, anything that's on wheels, you've got fuel surcharges. And then lubricating oil is obviously directly exposed to the oil price. So we see -- we're starting to see that, especially just here in April, and it may increase our OpEx slightly through Q2, and we'll see how long it goes. But again, those costs might go up, but we see it on the other side as far as revenue from the oil-based component of it.

Okay. Thanks. I just want to make a reminder that we've got our general meeting, it's in person. It's at our building here in the Plus 15 level at a mezzanine level in Calgary. It's next week, Thursday, May 21. If you haven't voted your shares, please vote your shares. There'll be a formal part of the meeting, followed by a brief presentation with the Q&A at the end and followed by some refreshments. So come and get your hat. Are there any more questions? Operator?

At this time, there are no more questions in the queue. I'd like to turn the call back to JP for closing remarks.

Okay. Well, thanks for tuning in, folks. We'll see you next quarter.

This concludes today's program. Thank you for joining. You may now disconnect.

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.

Thank you for standing by, and welcome to Peyto's Third Quarter 2025 Earnings Conference Call. [Operator Instructions]

I would now like to hand the call over to President and CEO, JP Lachance. Please go ahead.

Thanks, Latif. Good morning, folks, and thanks for joining Peyto's Third Quarter 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 is Riley Frame, our COO; 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 Michael Rees, our VP of Geoscience.

Before we discuss the quarter, on behalf of this group here and the management team, I'd like to sincerely thank the entire Peyto team, both here in the office and in the field, for their contributions to yet another strong quarter. And we had a busy quarter. It's carried on through into Q4. July was a little wet, somewhat unusually wet, and that slowed our activity in the month down a little bit. We had some plant turnarounds. We built and started up a new field compressor in Sundance. We added a fifth rig. We shut in some gas in September due to low prices. And most recently, we extended our credit facility. And that's just to name a few things.

Quarterly production per share was up 5% compared to Q3 last year, relatively flat quarter-over-quarter production at approximately 130,000 BOEs a day. But cash cost of $1.21 per Mcfe or $1.13 per Mcfe without royalties were down to their lowest level since we purchased the Repsol Canada assets in the fourth quarter of 2023. And that's not just unit cost due to some production dilution. That's absolute costs as well.

AECO 7A prices averaged a mere $0.94 per GJ or about $1.08 per Mcf when you account for the [ e-content ] of our gas for the quarter. But our strong hedge book added $87 million of gains or about $1.38 per Mcf for gas, and our marketing diversification contributed another $1.11 per Mcf, yielding $3.57 per Mcf all-in realized natural gas price, which equates to about 3.3x that of AECO for the quarter.

Putting all these elements together resulted in funds from operations of nearly $200 million or $0.98 per diluted share, and that's up from -- up by 29% from Q3 last year or 26% on a per share basis. We also achieved a top-tier operating profit -- or operating margin of 72% with a profit margin of 29%. And which at the end of the day, we feel is the most important. I mean, after all, it's generating profits, right? And it's those profits that we can return back to our shareholders in the form of dividends, which we paid out $0.33 per share in the quarter or a total of $66 million.

We spent $126 million of capital in Q3, up from previous quarters. So that's mainly due to the addition of the Sundance compressor station, the addition of a fifth rig later in the quarter and the Oldman plant turnarounds. Nevertheless, our payout ratio was just under 100%, and we were able to pay down a little more net debt of $20.5 million, bringing our year-to-date net debt repayment to $126 million. And I think more importantly, the increase in capital activity in late Q3 allows us to increase production into Q4 and Q1 and capitalize on improving winter pricing.

Okay. Let's talk a little bit about our operations during the quarter and so far into Q4. We had a couple of minor production interruptions in the quarter with planned Oldman turnarounds and some gas that we elected to shut in when prices went negative. But we also brought on a new field compressor in Sundance, which added some gas by pulling down the gathering system pressure. We brought on another rig in Sundance to help us catch up on the activity delayed from the wet July. And our drilling program shifted to the potent Notikewin, Falher and Bluesky species in the third quarter, and we're now drilling and completing what we think we expect will be the most productive wells of the 2025 program.

We don't amortize individual well rates, but we expect that these -- the wells that we just drilled in the second half of 2025 will -- to outperform those from earlier in the year, such that our full year vintage production curve should look a whole lot like 2024. And that really relates to the complexion of the species in the second half as compared to the first half. Of course, it isn't just the rates that matter. It's also the amount of capital that we deployed to achieve them, and we expect that these wells will rank as some of our highest rates of return projects this year. So what does all this mean? I expect we're going to set a new production record for the company in November, and we're well on our way and very comfortable to reaching our target of 140,000 BOEs per day exit for December, which correlates to the midpoint of our guidance of capital spending.

Also subsequent to the third quarter, we renewed and extended our credit facility for another 4 years. We rolled in what was left of the term loan that we put in place for the Repsol acquisition. So our new revolver -- revolving credit facility now stands at $1.05 billion, of which were drawn -- we were drawn $745 million on closing of that extension. We still have approximately $491 million of long-term private notes that mature at various times over the next 9 years. When you take all this together, it provides Peyto with a strong liquidity position to execute our business plan. It also shows the support of our lenders to Peyto's business plan and to our strategy.

I mentioned that we shut in some production in September, not because we were exposed to low AECO prices, our hedging and downstream diversification protects us from that. But because it made sense to have someone else pay us to take their gas, which we then use to fulfill our physical contracts and preserve our gas for better pricing in the future. Our diversification to other markets allowed us to gain a premium price of $1.11 per Mcf, as I mentioned earlier, over AECO, and that's net of the cost to get to those markets. Our physical and synthetic service to Henry Hub, Chicago, Dawn/Parkway, Venture and the Alberta power market all contributed to this gain, and we expect them to continue to contribute meaningfully into '26 based on the current strip.

We've released our preliminary capital budget for 2026. We plan to invest between $450 million to $500 million of capital next year to drill between 70 to 80 net wells. This program should add between 43,000 to 48,000 BOEs per day by next December and more than replace our estimated 26% to 28% corporate production decline over the year. If this sounds a lot like '25, it is. I guess the key difference here is that we plan to continue drilling with 5 rigs in the first half of '26, which should change the production profile and the capital profile to be a little more front-end loaded than in the past years.

We can apply the brakes and slow down the program in the second half if prices or the business environment warrants it. Conversely, we can keep it going with 5 rigs and aim for the high end of the guidance, if that makes sense. And this plan is consistent with our outlook on natural gas prices in 2026.

The preliminary program had us spending about 80% on new wells, with the rest going towards pipeline and plant optimizations. These projects will be undertaken to improve plant reliability, lower our costs and debottleneck field gas gathering systems to accommodate new drilling. We also have some minor plant turnarounds planned for later in Q3 next year, when prices tend to be the weakest. And maybe we'll get Todd to expand on -- with some details on that later. We will firm up the capital budget in February with our reserves release, which should also coincide with the full ramp up of LNG Canada if it all goes well.

So in closing, we think it was an excellent quarter, and we look -- as we look forward, we are well positioned to grow modestly, 5% to 10%, with enough cash flow not only to fund the capital program, but to return dividends to our shareholders and to continue to pay down debt over the next year. This is thanks to our prudent business strategy to keep the costs that we control as low as possible while protecting the revenues in the near term with our disciplined hedging strategy and derisking our sales markets to gas demand regions. This is manifested in stable long-term returns to our shareholders over the last 27 years, and we aim to continue that.

I don't think there's been a more optimistic time in the natural gas market with all the positive demand growth from both recent and future LNG build-outs in North America and the increasing appetite for power generation from gas in both U.S. and Canada. Heck, it looks like we've even got support from our federal government to the industry. And I think Peyto is well positioned to take advantage of these exciting times.

Okay. I think there's some -- probably some questions, Latif, for us. We can go to the phones if there's anybody waiting. If not, I do have some questions that have come in through email overnight.

[Operator Instructions] And sir, I don't show any questions at this time.

Yes, I will go to some questions I've received via e-mail. This one comes from Chris Thompson of CIBC. He couldn't make the call here this morning. One of his questions is, would Peyto continue to hedge gas volumes on forward strip given AECO basis remains wide for the foreseeable future? And do you believe that the basin is entering a period of increased production discipline given producer hedge books are rolling off and operators have an increasing exposure to AECO?

So I'll answer the first part of that. I normally would look to Mike. Mike has also got some -- having some trouble with his voice this morning. So I'll try and do my best. Mike, you can squeeze in if I miss an important point. But I think when we look at the business, we've always run the business prudently. And I think when we think about the business of hedging, we're going to continue to be -- our disciplined risk management program. We're going to navigate the stormy waters of AECO with care. We know this is a volatile market. So our hedging strategy, we don't plan to change our hedging strategy. As everyone knows, we have the guardrails, which we can land on between -- when we get to a certain season. So we'll continue to run the hedging program as we always have.

I don't know about the increased production discipline. I can't speak to other producers, and I don't know about other producers' hedge books and whether they're rolling off and what their exposure is or isn't to the market. But I do know that we don't change our strategy year-over-year around that. I guess we have some minimums that we like to accomplish, Mike. And I think that's obviously, minimum prices that we want to see. So we recognize that future prices are down a little bit from where we've been able to hedge. We've still taken some of that off the table. It's a price that works for us. But we'll continue to do that. So I would say our hedging strategy hasn't changed and won't change in the near future.

Another question Chris had was on our 2026 goals for cash costs and what we're thinking and what we -- how we achieve those goals. Maybe I'll turn that over to -- I think -- well, I think simply, there are two things that we're going to work on here. One is OpEx, and one is -- we'll always work on OpEx, it's the relentless pursuit of reducing those costs. The other one is just naturally interest costs will come down as we pay down debt. Over the next year, interest costs will come down on a per unit basis.

But maybe, Todd, do you want to elaborate? We've got some plans for next year on our facility capital. Maybe you can tie that into maybe how that helps us reduce our costs. And I would say all the target that we're looking at for cash costs for next year should be somewhere around 10% reduction, excluding royalties, of course. But maybe, Todd, do you want to comment on the operating costs?

Yes, sure. So obviously, we have a number of facility and projects -- pipeline projects on the go for next year, which will allow us to, I guess, see as much of the new wells that are drilled, which will help, obviously, OpEx dilution just through the increased production. But as well, we've been working on a lot of labor, I guess, efficiencies with the Edson plant and some of the other integration pieces that we've been able to spread out some of the labor amongst the field, which we're starting to really see bear some fruit.

As well, we've seen chemicals kind of come down a little bit. We're hoping that, that's going to continue or at least stay flat, which has really helped. Weather has helped a little bit. But obviously, through the winter months, when pricing typically goes up through this time, we're kind of seeing things hold flat, which is a good sign in the chemical market. So with those two things and sort of, I guess, our ongoing little pieces that we work on, we expect to see a pretty good drop, like you say, around 10% over next year versus what we've seen so far this year.

Thanks, Todd. I see there's a question there. Do you want to go to the phones there, please, Latif?

We have a question from the line of Amir Arif of ATB Capital.

Just had a quick question on that fifth rig. I think if I heard you right, in the capital budget, it's essentially in the year for half a year. And I'm just curious, what kind of spot gas price you need sort of to keep it for the whole year? And if you do, how much additional capital we can think about or additional production we can think about if the rig is extended from half year to full year?

Yes. So I think the difference in our capital program for next year than this past year is that we're going to front-end load a little bit more. I'll maybe get Riley to speak to what that means. But essentially, what we're suggesting, we're very happy, first of all, with rig and ops operating. So we feel like keeping it running. Last year, we had a rig out to do -- sorry, we got a rig on a window, had to drill a couple of wells, but it couldn't stay there because we would have filled up that plant and couldn't really effectively use it.

We're down in Sundance right now. Things are going well. We'd like to keep it running. So we're going to do that. And that just changed the complexion of the loading. Maybe we'll talk about that first. The price trigger, I think there's so much more than just the price. It's what have we been able to hedge, what have we -- what are our cost situations. So there's a lot that goes into that. I wouldn't say there's necessarily a price trigger. But if we kept the 5 rigs going all year around, that -- all throughout the whole year, that's the high end of the guidance, essentially. So we're moving it somewhere in the middle of the year, should we decide to, would be -- would get us towards the midpoint, I would suggest. But Riley, do you want to talk about the complexion of the program and maybe how it's loaded?

Yes. I mean, the complexion of the program from sort of an area and species perspective is going to be very similar to what we did this year. And JP alluded to the [ DCP ] and [ non-DCP ] capital. Allocation is very similar. But as it pertains to sort of the capital program for the year as we're towards that midpoint of guidance, we'll see it being sort of 55% capital front-end, 45% capital back-end loading. And then, yes, depending on kind of how the year goes and obviously prices playing a role in that, that could shift to 50-50 if we end up going to the high end as we bring on more activity in the back end with [indiscernible].

So the production profile will then sort of look that, and similarly as opposed to in the past, we've had more of a decreasing production profile in the sort of middle quarters because of activity. Now we're going to probably be a little more -- build that production profile a little steadier over the year, which is what I think you see in our corporate presentation materials for '26. So if that helps.

Absolutely. No, that helps, JP. And then just a follow-up question. Just on -- in terms of the cadence of the operating cost improvements you're thinking for '26, is it more tied to the looping projects at Sundance? Like, is it going to be more of a step change at a certain point in the year? Or is it sort of gradual as the year unfolds?

We have some projects that are planned that are optimization of the plant. Those are the ones that will typically help with that, other than the production growth itself, considering -- but we were stunned a little bit in Q2, as we didn't expect -- government costs now are roughly 30% of our operating costs, which is significant, right? That's the AER fees. That's the fees to pay the Orphan Well fund, that's property tax and that's a carbon tax. So we didn't have enough in our budget for the property tax in Q2. So we went up in Q2. So I don't know what surprises are around the corner.

But as far as what we control on that side, it will be the projects that Todd discussed. Typically, costs go up in Q1 because it's cold and we have -- we use more chemical. And costs decline as the rest of the year progresses, and that's what I think you can expect on the profile. Go ahead, Tavis.

I can add on your point on government costs and fixed costs in general, which is a lot harder to drive down yearly, they're 60%, 65% of our total OpEx. So we've only got 35% of that OpEx that we are really able to play with. And when you look at $0.50 op cost, that means you're talking $0.15, $0.16 that you can really control a lot more effectively than things like property tax going up higher than you thought or Orphan Well levy or AER, things like that.

Okay. And then just to clarify, should we be thinking about a 10% reduction to your average cost from this year, which is $0.54? Or 10% reduction from your current cost of $0.51?

I'd say the all-in cost for the year, year-over-year. We don't -- quarter-on-quarter is a tough one to call, right, like I just mentioned, because it can vary. So year-over-year.

Got it.

Okay. I have another question. If there isn't a question on the phone, I have another question that came in, which is more like -- we had some pretty low royalty rates. And I think that's one of the things we'd like to highlight. It was obviously, what was it -- 2.6%? For the quarter? I just want to ask Tavis how that -- how we see the complexion of our royalty rates going forward and what's sort of behind that 2.6% because it's obviously pretty low, one of the lowest in the industry.

Yes, JP, there are a few factors that contributed to the low royalties for the quarter. Firstly, low AECO. Again, we were $0.90 on a 7A basis, I think -- or $0.94. I think AECO was $0.60 per GJ. And AECO is really what drives the Alberta reference price that the Crown uses to charge us royalties.

And then secondly, we have a lot of our volumes diversified away from AECO. So we're getting really strong prices in the U.S. Midwest in Dawn and Henry Hub. So -- and those additional revenues that we're getting really aren't royaltied the same as the AECO stuff, right?

Yes, sir.

Next would be increased gas cost allowance credits. Those went up in Q2, and we're going to see those for the next 3 or 4 quarters. And then we also had lower NGL royalties from the decline in WTI and NGL prices. And I guess lastly would be just we have lower other royalties. We haven't done any wide sweeping, overriding royalty deals on our lands. So our other royalties are probably less than 0.5%.

Well, we haven't encumbered our lands with other -- besides Crown royalties, we're not encumbered with other royalties. So I think that's a testament to the way we run the business, pay me now, pay me later scenario, I guess, when you think about it if we had done that. So I guess we always think of royalties as not being a controllable cost. But in that sense, it would be if we were to burden our lands with a bunch of overriding royalties to others. So -- and that's 0.5% you said, roughly, run rate? And what's our overall run rate going forward here, do you think is a reasonable expectation given the strip?

Yes. I think for Q4, we're going to be in the 4% to 4.5% range. Next year, though, with the pricing strip, we're probably modeling more like 5% to 6%.

Okay. Right on. So back to the phones. If there's another call on the phone, we can take that.

Our next comes from the line of Mike Beall of Davenport.

This is sort of a macro question, but part of our bull story for natural gas is the increased North American exports of LNG. There's also some talk of a surplus later in the decade of LNG. Would that ever work against us in terms of North American pricing?

Well, I guess if you're referring to the fact that you might have too much LNG and it gets backed up onto the continent, then of course, that would have a negative impact on pricing in the future, if that's where you're going. And I think we've seen -- certainly, the U.S. producers have a lot of discipline in that regard to reacting to that with supply cuts and whatnot. So that's -- I mean, that's the big market, right, that will be affected.

In Canada here, we're working towards more export capabilities to help our local market. And that's encouraging as we think forward beyond just this year, we've got LNG Canada slowly getting going here, but we also have other projects on the come. So it's good for the overall future out there.

But that's one of the reasons, Mike, we think about hedging, and we think about taking that risk down and we want to be exposed to different markets so that we can weather those storms, and we feel that they'll be shorter term, and we can weather those storms when we've had an active and continue to have an active hedging program. We still believe gas will be one of the most volatile markets, and we want to be able to smooth those revenues out, right, smooth out that volatility.

Right. Okay.

Okay. Any more questions on the line?

I show no further questions from the phone lines at this time.

Okay. Well, thank you very much for participating in the call. I appreciate the engagement and the involvement, and we'll see you next year.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.

Hello, and welcome to Peyto's Second Quarter 2025 Financial Results Conference Call. [Operator Instructions]

I would now like to turn the conference over to JP Lachance, President and CEO. You may begin.

Thanks, Towanda. Good morning, folks, and thanks for joining Peyto's Second Quarter 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 is Riley Frame, our Chief Operating Officer; Tavis Carlson, our CFO; Todd Burdick, our VP of Production; Mike Collens, our VP of Marketing; and Mike Rees, our VP of Geoscience.

Before we discuss the quarter, on behalf of the management group, those that are here and not here, I'd like to thank the entire Peyto team, both in the office and in the field, for their contributions to another strong quarter.

Peyto remained active with 4 rigs during the second quarter through spring breakup. As is typical for Peyto, production falls a little through Q2 as we try not to overspend, fighting through the mud to complete wells and bring them on production.

The fires near Fort Mac did cause some oil sands shut-ins that affected demand for natural gas in the province. And there were some NGTL maintenance that caused prices to go negative, at least for 1 day in June. We did shut in some production that day, not because we had to, but to be more opportunistic and essentially get paid to fulfill our physical contracts and save our gas for another day. This had a marginal effect on production for the quarter, but I bring it up because it's something we'll continue to consider as we move through the summer.

Quarter production was just under 132,000 BOEs a day, up 8% since second quarter of 2024. And our cash costs were down 13% over the same period to $1.31 per Mcfe as we continue to lead the industry in that regard.

Our strong hedge book added $53 million in total gains, which added $0.75 per Mcf to our realized gas revenue. And our market diversification contributed $0.53 per Mcf net of transportation costs over and above the monthly AECO pricing.

All these factors combined to increase funds from operations by 24% year-over-year as we generated $191 million in the quarter or $0.95 per diluted share, which was also up 20% from Q2 last year.

We did not have much gas exposed to AECO pricing in the quarter since we have Empress service, which can net us better realizations to AECO, particularly when access to storage is restricted, which happened in Q2. In fact, we sold some of our excess Empress service during the quarter, allowing us to collect incremental income along with third-party processing at Brazeau. That added $0.07 per Mcfe to our sales revenue in the form of other income.

Our operating costs were slightly higher, $0.01 higher than the prior quarter. While our controllable operating costs were down quarter-over-quarter, we received our 2025 property tax bill in Q2 and it was higher than anticipated. So that resulted in an adjustment that's reflected in the higher op costs.

Despite this, we remain laser-focused on continuing to produce the costs that we control, and we're forecasting lower operating costs for the rest of the year. And I might get Todd to elaborate on that later in the call.

Royalties were a lot lower in the quarter than last year because of weak AECO prices and increased gas cost allowance credits. And we expect royalty rates to be around 5% for the remainder of this year based on the current strip.

Interest costs were also lower in the quarter as interest rates have come off and we continue to reduce bank debt. In fact, we paid down $40 million of net debt in the quarter and $105 million year-to-date.

So taken together, our cash costs were down $0.11 per Mcfe quarter-over-quarter and $0.19 relative to second quarter of 2024. So all in all, we have the lowest cash cost in town, but more importantly, I think one of the highest in margins as, of course, you know, our low-cost structure and our strong hedging and diversification strategy allowed the company to weather volatility in the commodity markets.

Switching to operations. We drilled 19 wells in the quarter, completed 19 and tied in 21. Part of the drilling program included follow-ups to the Q1 Cardium wells that were drilled in Brazeau, where we used a different drilling and completion design. We talked about that then.

The first 2 wells we drilled were low working interest, which helped us to test the concept. The next 3 wells that we followed up with in this past quarter, we're at 100% to see and make sure we could repeat the results.

At the end of the day, the key takeaway here is that we reduced our drilling and completion costs per meter by about 37%, and that should really help us as we look to improve the economics of future Cardium locations across our large inventory.

Wilrich continues to perform well as I detailed in the recent monthly letter, having dialed in our most recent design and applying it to the high-quality land we acquired from Repsol. We also completed another well in the prolific Falher channel trend in the quarter that we discovered last year in the Greater Sundance area. That well has already produced over 1 Bcf of gas, and it's the best outcome on this trend so far.

We have since drilled a follow-up well that we'll be completing shortly, which will help us delineate the trend and give us -- give the team more confidence in the 20-plus locations that we see in the play.

We started construction of a 30-million-a-day field compressor station in the Greater Sundance area. It will move more liquids-rich gas to the Edson gas plant via the Central Foothills Gas Gathering System later in Q3 into Q4. And again, I might get Todd to elaborate on the details of that project later. That's going to help clear out some existing gathering system for a large-scale development that we have planned in the area that will go to -- will take gas to Swanson and Oldman.

The long-awaited LNG Canada facility exported its first cargo right at the end of the quarter, I think it was June 30. We expect this will be constructive for the basin in the long term, but we should be patient as things ramp up here.

In the meantime, we have plenty of production hedged for the summer, about 500 million cubic feet a day, priced at $4 an Mcf. And the rest of it is diversified to hubs in Eastern Canada and Chicago and the Midwest where prices are stronger.

Our business plan and guidance for 2025 remains unchanged. We plan to spend between $450 million to $500 million to generate production adds at a cap efficiency rate of about $10,000 to $11,000 per BOE per day by the end of the year. That should more than offset our annual corporate decline, which we estimate is about 27%.

We had a large number of potent [ non-QM ] locations and more of that new Falher channel wells planned for the rest of the year. We expect these locations will bring our annual average productivity back to something similar to last year's stellar performance.

We also have some Bluesky and Viking wells planned that will follow up on past successes as well.

We're not slowing activity per se because we want to keep our crews steady, and we want to -- as we expect to ramp up production in Q4, which will coincide with better winter pricing and as LNG progresses to full capacity. But of course, we will remain flexible with our plans as we always are.

At the end of the day, we sell a product the world needs, and we run our business in a way that is sustainable. We keep our costs as low as possible. We diversify our sales points, that we hedge the near term and we -- so that we can confidently fund our capital program, reward our shareholders with profits.

It's simple, it's predictable, maybe perhaps a little boring. But we make no apologies for that.

Okay. I imagine there are some questions. So Towanda, perhaps we can go to the phones first.

[Operator Instructions] Our first question comes from the line of Chris Thompson with CIBC.

Just to start out, you talked about some of the recent successes at Chambers and the new well -- or design. Just wondering how does that compare to other competitors in the area? Is Peyto sort of at the leading edge of this approach? Or is this something that you've seen other operators do and now you're adopting?

Yes. As far as the -- I mean, obviously, we mentioned that, I think, last quarter that this is something that isn't something new in the industry. It's something that others are already doing at least in the oil part of the play.

So the concept of going -- drilling a bit lower to the biodegraded zone just helps us with penetration rates, we talked about this last quarter. And so I wouldn't -- I don't know if there's a lot of gas guys doing this per se. I'm looking at Mike and Riley here and they're [ turning ] their heads no.

So we might be -- there may be a couple of other companies doing it. So I don't know that we lead, but it's certainly an improvement for us and it's important for our long-term Cardium inventory to get those costs down right.

Okay. And then, I guess just sticking to that Chambers and Brazeau area. Can you maybe expand a bit on the third-party gas that you're bringing in there? I think you mentioned $0.07 an Mcfe. Just was that specific to Brazeau?

That's a combination of us selling some excess Empress service and the Brazeau processing fee income that we would have received.

But it's not just Brazeau. Maybe I could get Todd to elaborate on some of the other sort of sources of our third-party fee income. Todd, do you want to comment on that a little bit more? It's not just that area, though, just to be clear, Chris.

Yes, for sure. Definitely some opportunities, some further opportunity in the Brazeau area. I think we mentioned last quarter when we commissioned that pipeline, we built it so that we can add and we've been -- our JV group has been busy talking to others in the area.

And then up in Greater Sundance, we've had some producers that have been sending third-party gas to our Swanson plant for quite some time. We've been talking to others up there. The JV group is pretty active. We've got a little bit up in Kakwa. So it's kind of spread out all the way from Kakwa down to Braz.

So it's definitely not just happening in Braz, and we're always working with other producers who may be looking to shut down plants or other things and it helps them on their OpEx and helps us on our -- on the other income part of the balance sheet.

Got it. And then just this next one for JP. How are you thinking about capital allocation as we think out 2026 and beyond between organic growth and M&A, and then as you approach your debt targets, potential shareholder return increases.

Well, we still believe that we're going to put money into the drill bit to grow modestly over the next 2 years. We don't have -- we haven't come out with a formal plan for '26 yet. Certainly, that's -- it probably is going to look a lot similar to the last 2 years from what we can predict at this point in time. We'll see where prices and everything goes from here.

But -- and we'll continue to make debt repayment a priority, but we have a soft debt-to-EBITDA target of 1x, trailing 12-month EBITDA of 1x. And so that hasn't changed. And when we get there, which we expect will be sometime in 2026, we'll relook at that capital location strategy.

But that depends on where prices are at. LNG Canada came on and things, AECO price, the differential -- or the basis between that improves, all those things happen, and we'll start looking. And depending on our diversification and all those things, we'll look at where -- how we see the market and how the business is. And we'll decide then how we change that allocation if we change that allocation to where it is right now.

But we've got a fairly comfortable dividend level right now that we feel is very sustainable, and we're going to continue to grow. And nothing really has changed from what we've been messaging all the way along, Chris.

Got it. And then just last question for me, JP. You touched on AECO improving. How are you thinking about the marketing strategy here? It looks like your 2027 book has a pretty sizable exposure to domestic benchmarks and relatively light on the fixed, which we expect will increase over time.

But how are you thinking about that? And which hubs do you see as having attractive pricing on the strip that you would be looking at?

We still believe that diversification is important. And diversification doesn't mean not AECO. But -- so AECO is part of that, and in fact, our exposure to AECO is in the fact that we would like to hedge some of that in the future, right?

So as we move closer to '27, we'll build that up because nothing has changed in our hedging strategy plan, right? When we get to '27, we're going to be -- any season there in '27, we're going to be minimum 50% hedged because we know volatility in commodities is real.

As we move forward, we're going to continue to bring up the hedge book in '27. And when we do that and right now prices in '27 at AECO are pretty good, so as we take some of that off the table and we see maybe the effects of LNG Canada narrow that basis, which improves that even more, then we'll take some more of that off the table and then we'll have similar exposure going forward as we have today.

Some AECO, a little bit AECO, a little bit of everything else, too. We think that's important not to have just one market. So we're not -- we think it's good. We want it to improve. But we're not counting on it as it were.

So it doesn't sound to me like having additional exposure to AECO is -- compared to where you've historically been in the last couple of years is something that you'd be really looking for?

Yes. We're only -- look, remember, we only hedged 2 and 3 years out. So to the extent that AECO improves, we have a whole lot of reserves that will be exposed to that in the future should AECO really start to run it, becomes, say, a premium market or something different than what it is today, right?

So this is a short -- managing things in the short term. So I don't think -- I don't see us changing our strategy in that regard.

[Operator Instructions]

Towanda, I have some questions here from -- that have come in overnight. So maybe I'll just -- if it's okay, I'll ask a couple of those here of the team?

All right. I'll hand it back to you.

Todd, we did talk about earlier about a little bit the compressor that we're going to install, we've already started construction on next year.

Some questions around, okay, what is -- can you elaborate a little bit more? Where is this? And how is it going to help us?

Sure. So the compressor is, I guess, best described as the sort of the heart of the Peyto Sundance area. Geographically, township 5321 West 5 for those who are familiar with the area.

There's a lot of vertical penetrations in the area, a lot of horizontals and Cardium, Notikewin, Falher, Wilrich. A lot of depletion. And with the Repsol acquisition, obviously, as JP mentioned, there's a development plan in the area. And when we looked at it, we said there's a lot of production here that needs to be protected from higher line pressures when you're bringing on these bigger wells.

So after doing some sensitivities, it made a lot of sense to take and build a compressor, collect that older gas, which is a lot of Cardium and Falher and Notikewin, as I mentioned, that's the bulk of it. And with the pipeline infrastructure that we bought, along with the Repsol acquisition, it allowed us to tie that gas in with some modest pipeline expenditures down to the Edson gas plant where we can get a lot better liquid recovery from -- especially the Cardium versus Oldman or Oldman North. Oldman obviously had the deep cut, but Edson had much better recoveries and some of this gas went to Swanson.

So we're going to collect about 30 million to 35 million a day initially. We built the plant so that we can expand it to that 60 million to 75 million cubic feet a day just with another dehy and some more compressors. We're expecting to see somewhere around a 10 barrel per million uplift on the gas moving either from Swanson, Oldman, Oldman North down to Edson, could be better. It will depend on the species.

And then along with that, as I mentioned, you take -- and I think JP alluded it in the press release, you take 35 million a day out of the gathering system that's going to Edson -- or to Oldman and Swanson, you're going to free up room. You're going to see some flush until we backfill that production with new production.

And as well, all that 30 million a day of gas that you're sending to Edson is now going to be at a lower line pressure, probably half. So that helps the economics of those wells long term.

So a lot of little parts that come in play into the advantage of building this compressor station.

Things are going really well. We're probably 1 month out, maybe a little bit longer until commissioning. We're -- the guys have been -- despite the rain, we've got shut down a little bit and had some delays, but things are moving along really, really well.

Okay. Good. Thanks. Thanks, Todd. Another question was about the well outcome so far this year. Maybe I'll get Riley to address that just the whole case.

So we expect some improvements on the back half of the year. Can you talk about the kind of species we're going to be drilling? Can you elaborate a little more -- maybe just as a little more color on that.

Yes. Yes, you bet. So when we look at the performance for the first half of the year here, we're actually very happy with where we're tracking relative to where we were last year. If you guys recall, 2024, we had a much more Wilrich-centered program in the first half of the year and a much more [indiscernible] Falher-centric program in the second half of the year.

So very similar to '24, I think what we'll see is that curve improve as we move forward through the second half of the year. And when we distill it down to what's really important here, looking at what we're spending for what we're getting, I think we're right on track with 2024. And so I would expect us to be in line with those numbers as we move through the second half of the year.

Okay. We talked about in the press release and I mentioned it here earlier, we're following up on some past successes. It's not a plays -- a couple of plays that we haven't done in recently. And one of the questions was Viking and Bluesky. It's not something that people -- I guess, the investors hear a lot about.

So maybe I'll get Mike to elaborate a little bit on what we're pursuing there in the Viking and Bluesky here this year later -- later part of this year.

You bet, JP. So it has been a little while since we dipped our toe into the Viking. We drilled our first Viking well about 2 years ago, and that was a fairly successful first test for us on our lands. And we're looking to wrap up actually the second well through all that in the Viking right now. So you see a material amount of upside on our land base in the Viking and also on the Bluesky.

We haven't actually drilled the Bluesky for a while, I think that goes back about 5 years to 2020. We did inherit as part of the Repsol acquisition a Bluesky well that Repsol had drilled but we completed. And that turned out to be quite a good well. So again, material upside in the Bluesky on our existing land position.

So we are drilling the first Bluesky well currently and we have a couple more plans for the remainder of the year. But should the results come in as expected in these 2 zones, we will be more aggressive with them in the future.

Okay. Thanks, Mike. I don't know if there's any more questions from the phone lines, Towanda?

[Operator Instructions] I'm showing no further questions in the queue.

Okay. Well, thanks for tuning in folks. We'll see you on the next call in November.

Ladies and gentlemen, that concludes today's conference call. Thank you for your participation. You may now disconnect. Everyone, have a wonderful day.