Peyto Exploration & Development Corp. (PEY) Earnings Call Transcript

Ladies and gentlemen, thank you for standing by. Welcome to Peyto's Second Quarter 2026 Financial Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would like now to turn the conference over to JP Lachance, President and Chief Executive Officer. Please go ahead.

Thanks, Michelle. Good morning, folks, and thanks for joining Peyto's Second 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 most of the management team, including Riley Frame, our Chief Operating Officer; Derick Czember Carlson, our CFO; Todd Burdick, our VP of Production; Derick Czember, our VP of Land and Business Development; Mike Collens, our VP of Marketing; Crissy Rafoss, our VP of Finance; and Mike Rees, our VP of Science. Before we discuss the quarter, on behalf of the management group here and as always, I'd like to thank the entire Peyto team in the office and in the field for their contributions to another strong quarter. It was a wet spring in early summer in the areas that we operate, so we had a lot less activity in the field, especially when you compare that to Q1. We have managed to maintain production levels more or less at the same level, thanks to a strong drilling program in Q1. While we paid down some more debt, we increased the dividend in May. We drilled more great wells, we added more undeveloped acreage, signed another important natural gas diversification deal as well. I think that's a pretty good for a typically quiet quarter. Let's dive into some details with operations first. We lowered drilling activity down as we typically do during the spring breakup. We only spud 10 wells, which is reflected in our capital spend of only $68 million in the well-related costs and includes some completions that would have spilled over from Q1. 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 Brazil. We applied the same drilling and completion strategy that worked so well last year in the area, just off there in chambers. This is where we drill a little deeper in what we call the bioturbated zone to increase the drilling speed and then we complete the longer horizontal with more stages to increase stimulation intensity. The gas rates are better, but most importantly, so are the wellhead liquids. We have initial liquid rates of 400 to 600 barrels per day. And now we're applying our Cardium learnings up in the Sundance area to see if we can repeat those results and improve the internal rates of return up there as well. Peyto also invested $14 million in facility projects that include -- included major pipelines, play optimizations and some maintenance work during the quarter. We've completed some plant turnarounds with a minimal effect on production since we -- we plan these -- when we plan these, we try to redirect volumes to other plants and state shutdowns to minimize or to maximize online time. And maybe I'll get Tavis to expand on that later. But the credit of these efficient turnarounds goes in part to the great execution by our team in the field, but also to the plan that was into these things in the office. This is an element of our own and control strategy that I think is often overlooked. We're not dependent on third parties performance for these kind of turnarounds. The majority of our gas -- 98% of our gas is controlled by us and goes to our plants. The balance of our capital was spent in Q2 -- a balance of capital that was spent in Q2 was $2 million is used to capture another 26 sections of land through Crown sales and direct purchases. That brings new land purchases so far this year up to a total of 53.8 net sections at an average cost of $158 per net acre, which cheaply adds to our unbooked drilling inventory. At the start of Q2, we redirected about 85 million cubic feet a day of sales gas to a third-party deep cut facility to increase our C3 plus or our propane butane recoveries, mostly on some condensate, which adds to our incremental -- which adds an incremental 1,500 barrels per day, and that's helping to bring our corporate liquid content up from 12% to 13%. And the other part of that is the Cardium program, of course, it's adding some more liquids. Switching to financials. Controllable cash costs in the quarter, that's operating transport interest and G&A totaled $1.04 per Mcfe which brings us down to the pre Repsol levels before Q4 2023. And that speaks to the rate effort by the Peyto team to stay focused to integrate these assets into our low-cost model. Flipping to revenue. Another strong quarter where our realized gas price was $3.42 an Mcf, which is double the average ACO monthly for the quarter, which was $1.64 when it's adjusted for per Mcf when you adjust that for our heat content. Once again, the diversification value of [ $0.093 ] per Mcf played an important role and the rest of the game we saw was from $0.85 of hedges. Speaking of diversification, we added another piece of our -- to our portfolio in Q2 with the Centrica gas supply agreement that fetches us TTF -- European TTF based pricing less deductions. That starts sometime in 2029 and delivers 50,000 MMBtus at net or at AECO at a very attractive netback. Of course, the agreement is confidential, but it does bring our total unhedged diversified volumes, so that's non-AECO price-related volumes to 400 million cubic feet a day in 2028 and beyond. Combine the low cost and the great pricing that we got, at least relative to AECO, meant we generated $228 million in funds from operations, that's $1.11 per share and adjusted earnings of $1 or $150 million or $0.50 a share, and we have continued to impress with an operating margin of 71%. We now come on to a dividend increase of $0.01 per share. That's 9% in May, that was paid out starting in June, and we still paid down debt of total net debt by $72 million. There's no rest for the win, and we're back up to run 4 rigs. We expect to hold that there for the rest of the year. We've continue to modify our drilling program going forward to shift even more towards some of the liquid-rich species like the Cardium and flare. And you can refer to the latest corporate presentation for reference to that. I think it's on Slide 21, is your breakdown of the species that we're going to drill this year and the fullness of this year. We remain well protected for the rest of the year with just over 500 million cubic feet a day of gas hedged over $4 an Mcf and about 400 million cubic feet a day secured for 2027, at least so far, at $3.30 an Mcf, both of which are higher than current strip, which is good and bad. The rest of our production is pointed to downstream markets and essentially no -- really no summer exposure to spot a prices through 2027. When combined with our liquid hedges, that secures $485 million for the rest of '26 and another $590 million for 2027. This, along with our industry-leading cash costs, our market diversification and the great well results we're seeing gives us the confidence to remain committed to our guidance, which is investing $450 million to $500 million drilling 8 net wells for 2026. We remain constructive for natural gas with the continued tailwinds that are presented from LNG Canada and both -- sorry, LNG build-out in Canada and the U.S. and the increased demand from local markets like power for data centers, strategy remains the same. We focus on execution, to all things that we can control as cost while mitigating the risks on the commodities, you know how we do it. We believe this is a winning recipe and it provides long-term returns to our shareholders in a very volatile commodity market. Okay. I imagine there's some questions, Michelle. So maybe I'll turn it over first to the phones. And I've got some other questions that come in overnight, but maybe Michelle will start with anybody on the phone who wants to ask a question, go ahead.

[Operator Instructions] At this time, I am showing no questions in the queue.

Okay. Maybe I'll give some time for people to think, and I will turn to -- I have one question to come in about a little more information about what we're doing with this Cardium play, and how we might be applying that up in Sundance. So maybe I'll ask Riley to maybe expand upon that a little bit with respect to how we're doing and what we're doing in the Cardium these dates.

Sure. Yes. So like we've talked about mostly over the last little while here, we've been active in the Brazeau area. We're going longer sort of help fix -- amortize the fixed cost of our wells drilling in the butter zone to increase our ROPs. And then obviously, we're increasing our stimulation intensity to try to improve on our per meter performance. So like we talked about in the press release, that's translated into a 37% improvement in our drilling cost per meter horizontal, which is a huge improvement. But we still think there's room to work on the condition side of that. So one of the things that we did here just recently with the last pad we drilled was we tried to coil shiftable sleeve system. There's some significant advantages to that system as we start talking about cemented liner systems. So we just finished up those completions here recently. So it's still early, but -- everything is look pretty positive that we've actually been able to move costs in the right direction there. So we're on track to see an even larger cost reduction on a per meter basis as we go forward. So translating that over to the Sundance area. We recently drilled our first patent Sundance since 2022. Really try to take what we've learned from Bras and apply that as best as it's not completely translatable. There's a few differences. But the main goal here was to try and drive horizontal lengths longer. So this first pad, we were able to increase or on length by about 50%, which is pretty meaningful. The big difference up in Sundance would be that we don't really have the biocabinet chase. So going low and improving that ROP in that biocabinet option. But that length increase is still meaningful as it pertains to decreasing the per unit cost as we're drilling these wells. And then the other part of it would be increasing the stimulation intensity and driving that tonnage per meter number of beds try and get higher per meter rate. So overall, the first couple of wells we drilled here, it looks like we've been able to reduce our horizontals per meter cost by about 10% on the far side, which is a good starting point. I think we'll continue to try and move that further down. Those wells were completed just sort of again late last week here. So it's still early time. But overall, it's very encouraging, and I think it will really help us to drive improved economics in Sundance Cardium across the board where we have obviously a lot of reserve books and a lot of reserves booked as well as a lot of locations. So stay tuned on that as far as where we go that.

Okay. It sounds good. I think what you're -- yes, so essentially, we're trying to pull out both levers, both the cost side and right, and the production side because, of course, what matters most is returns, not just increasing production as well as cost matter, as you point out. So that's good. . Yes, exactly. So another question that came in was this new term we've introduced in our press release or in our MD&A as well called adjusted earnings. I just wondered maybe, Tavis, to give you a cast sort of explain that maybe in payment terms a little bit more what do we mean by this adjusted earnings -- mainly stems from our new Centrica gas supply.

TTF component of this contract is viewed as an embedded derivative, and we have to separate that from the underlying ACO component of the contract, account for it as a derivative financial it. What that means is we have the mark-to-market is component every quarter report that change in value P&L. And this mark-to-market change is going to cause quite a bit of volatility in our earnings going forward where it could potentially cause quite a bit of volatility. So we've decided to add a new non-GAAP measure to our disclosures that's going to take earnings, and we're just going to back out that unrealized gain or loss for the quarter. And we believe that give investors a clear picture of our current operating performance without the noise is noncash.

Excellent. Okay. Thanks for explaining that for folks. That's good. And one last question to come in about draw around, maybe, Todd, you can -- I mentioned it in my opening remarks, you could expand a little bit more on how we do this because I think it's something we think we're proud of and how we manage our business and how we keep production on the uniqueness, I guess, or potentially uniqueness of our way our gathering systems and plants are all connected, that allows us to do this. Maybe you can expand on that a little bit more, too.

Yes, sure. And yes, thanks for recognizing the planning that goes into turnaround the execution from our Asset Integrity group, our Field Forman, our operators who are out there doing the work when turnarounds are happening. So they do a great job. Sometimes they have to pivot mid turnaround because we're going into vessels and we're looking and doing UT and that sort of stuff and all of a sudden we see something needs to be repaired. And so they do a great job of minimizing the downtime. But -- yes, given the interconnectivity, especially down in bras, we've got three plants that are essentially interconnected. And then obviously, in Sundance, we've got many plants in total that are interconnected. We're able to move gas from plant to plant, still seeing some production losses, but it's mitigated substantially. We get three plants in the quarter, two were in Sundance. And out of those two plants, we only saw for the quarter, about 400 BOE a day loss on the quarter. And then the third plant was Brazeau, we were able to divert gas to chambers and to Aurora. And that only accounted for 100 BOEs on the quarter. The other part is the modularity of our plants. So we might have two in lets out of plants, and we've got multiple processing trains. So -- in a lot of situations, we're able to keep part of the plant running and just focus on the part that needs to be inspected. We've got them usually in 5-year intervals. So you might have 1 in let that 5 years and the other inlet that's sort of opposite for other vessels. So we're able to keep part of the plant running, not only, but we try that, we do a buy design to minimize the impact on a particular plant at one time. So we did one plant at the beginning of Q1, Kakwa is a small plant. That went really quick. And we've got one more here in Q3 starting next week in Swanson. Same thing we'll keep about half the plant running, we'll be able to push a little bit more through one train and then we'll have gas going up to -- down to the Edson plant over to old Manantryand minimize the downtime -- year with 5 turnarounds.

Yes. Okay. Well, thank you. Thanks again, thanks to the team in the field and everyone that's involved in how to do those folks in the office that have to make sure all this runs the way it does. And so -- so it looks like no questions. Is that correct, Michelle?

It's correct.