Peyto Exploration & Dev (OTC:PEYUF) reported third-quarter financial results on Tuesday. The transcript from the company’s third-quarter earnings call has been provided below.
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Summary
Peyto Exploration & Dev reported a 10% year-over-year increase in production, with liquids production up 20%, primarily driven by Cardium drilling.
The company invested $100 million in well-related capital and $23.5 million in facility projects, including major pipelines and plant optimizations.
Controllable cash costs decreased to $1.02 per Mcfe, achieving the target of a 10% reduction from the previous year.
Realized gas prices were $3.50 per Mcf, supported by diversification and hedging strategies, contributing to $221 million in funds from operations.
The company paid down $24 million of net debt, maintaining a debt-to-EBITDA ratio under 1.
An increase in the monthly dividend to $0.13 per share was announced, reflecting an 18% increase over the previous year.
The preliminary capital budget for 2027 is set between $475 to $525 million, with a focus on increasing liquids production, particularly through Cardium formation drilling.
Future diversification efforts include a new service agreement for 80,000 GJs per day to Ontario, enhancing the non-AECO portfolio.
The company maintains a positive outlook on the natural gas market, supported by LNG export demand and supportive government policies.
Full Transcript
OPERATOR
Good day, and thank you for standing by. Welcome to the Peyto Exploration & Dev third quarter 2026 financial results conference call. At this time, all participants are in listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again.
Today’s conference is being recorded. I would now like to turn the conference over to your first speaker today, JP Lachance, President and CEO. Please go ahead.
JP Lachance (President and Chief Executive Officer)
Thanks, Marvin. Good morning, folks, and thanks for joining Peyto Exploration & Dev’s third 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 the entire management team including Riley Frame, our Chief Operating Officer; Tavis Carlson, our CFO; Lee Curran, our VP of Drilling and Completions; Todd Burdick, our VP of Production; Derek Sember, our VP of Land and Business Development; Mike Collins, our VP of Marketing; Christy Raifous, our VP of Finance; and Mike Reese, 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 here in the office and in the field, for their contributions to another big quarter.
They should be proud of their achievements keeping Peyto a super-efficient operator. We were back rolling with four rigs after breakup, but wet weather that continued into July really slowed down other activities for a while. We continue drilling great wells across all core areas in multiple horizons, but with a real focus on the Cardium, which gives us more liquids than the other formations. We added some more service to our diversification portfolio to Eastern Canada and we continue to add future drilling inventory through more land purchases, all getting a great price for our gas and continuing to pay down more debt.
So let’s dive into some details, starting with operations. First, production was up year over year by 10% or 7% per share, but most importantly, liquids production was higher by 20% led by recent Cardium drilling and increased NGL recoveries. Production was down a little from Q2, but that’s just the typical lag that we see due to lower capital activities through breakup. Despite the wet weather at the start of the summer, Peyto invested $100 million in well-related capital.
We’ve continued to drill some great wells up and down the abundant Deep Basin stack, but we’re particularly pleased with the latest Cardium wells in the Wild River area of Sundance. We completed and brought on a three-well pad that was designed to test elements of what we’ve been successfully doing down in Brazeau. Although one well was called short due to encountering some natural fracturing, the other two wells were drilled 50% longer than previous wells in the area.
These wells have delivered improved performance over prior programs and reduced cost per meter of 11%. There’s a slide in the corporate presentation that I would encourage you to review, which highlights the changes and shows the superior performance. These wells exhibit initial rates of 6 million cubic feet a day of gas with about 55 to 90 barrels per million of liquids. Their initial gas rates are not as prolific as our Spirit River wells, but obviously they generate better returns with the dichotomy between oil and gas prices today.
Meanwhile, in Brazeau we continue to follow up on prior success and drilled three more wells in the quarter that have been brought onstream recently and continue to validate our new drilling recipe down in that area. In both these areas we believe there’s further room for improvement, which is important because we have a large portion slated for the 2027 capital program, but also because we have a large portion of our undeveloped booked reserves attributed to this formation.
Peyto also invested $23.5 million in facility projects that included major pipelines, plant optimizations and some maintenance work during the quarter, including a turnaround at the Swanson gas plant. The balance of the capital, about a million dollars, was used to capture another 10 sections of land through Crown sales, and that brings our new lands purchased by Crown sales and deals so far this year to a total of 63 net sections at an average cost of $157 per acre, which cheaply adds to our unbooked drilling inventory.
Switching to financials, controllable cash costs in Q2 — that’s operating, transport, interest and G&A — totaled $1.02 per Mcfe. That’s down again from last year and Q2. That more or less gets us to our target to reduce controllable costs by 10% from last year, and this is driven by savings in operating, transport and interest costs. We’ll try to hold on to that in Q4 and I’m certain the Peyto team will remain tenacious. Flipping to revenue, another strong quarter where our realized price for gas was $3.50 per Mcf, which is over double the average AECO monthly. For once again, Peyto’s strong diversification portfolio contributed a value of $1.00 per Mcf — that’s net of costs — while our systematic hedges added another $0.82 per Mcf to what would have been $1.68 per Mcf if our gas had just received the AECO monthly price. Cumulative hedge gains since inception are up to $848 million, suggesting our disciplined program is working.
Over the last three years Peyto hedge gains have added about a dollar per Mcf to our realized gas price while the diversification program has added about $0.80 per Mcf net of costs. Speaking of diversification, on the heels of our recent 50,000 MBtu deal with Centrica for TTF-based gas supply in Q2, Peyto Exploration & Dev added another 80,000 GJs per day — 70 million cubic feet a day — of service to Ontario where we fetch Parkway pricing via the TC Mainline starting in November 2028. This adds to our future diversification, our non-AECO portfolio, to get it up over 500 million cubic feet a day which we can hedge or we can let float depending on where the market goes.
Combine the low cost, the increase in liquids, the great pricing at least relative to AECO meant we generated $221 million in funds from operations, or $1.06 a share, adjusted earnings of $105 million, or $0.50 a share, and we put up another strong operating margin in Q3 of 71%. On top of that, we paid down about $24 million of net debt and that keeps us under our 1 times debt to trailing 12-month EBITDA. As we look forward, we’re comfortable with another increase to our monthly dividend this year, bringing it up to $0.13 per share per month. That’s the second bump this year and represents an 18% increase over last year despite doomsday El Niño threats. In the short term we feel very comfortable with this increase since our revenue remains well protected for the rest of the year and through 2027, with just over 400 million cubic feet a day of gas hedged at $3.32 per Mcf for 2027 with very little exposed to the AECO market.
When combined with our liquids hedges, that secures $690 million for 2027. This, along with our industry-leading cash costs, market diversification, increase in liquids, and our long-life reserves, gives investors confidence in the stability of that dividend for the future. Speaking of the future, the Board has approved a preliminary capital budget for next year between $475 to $525 million, which is up slightly over prior years simply because we’ve grown the business. But the capital efficiencies we expect to attain remain the same: $10,000 to $11,000 per flowing boe production adds by December 2027. And with our estimated decline between 26% to 28%, that should equate to an exit of approximately 157,000 boe per day — the midpoint of all those numbers — with an increased liquids share by year end approaching 15%.
This increase in liquids we expect to come from a large Cardium focus that we have for next year, following up on the successes I mentioned earlier. In fact, over one third of the drilling program will target this formation. All in all, we expect liquids will grow faster than gas in 2027. And that’s the important takeaway here. Our production growth on a boe per day basis may not be as high as anticipated, but the increase in liquids mix will generate more cash flow, which is really all that matters.
Of course, we’ll remain flexible on capital spending, but also on the formation mix should the business environment change. And of course, we’ll confirm the capital budget in February with our reserve report release. On the macro, there’s lots to get excited about for the future of natural gas in Canada with LNG export demand growth, the continued interest in data center power demand, and the prospect of future gas required to fuel oil sands expansion. I think for the first time in a long time we have governments all around us that support the business. The Fed’s recently announced the productivity mega deduction which should be meaningful to companies, assuming it gets passed.
But regardless, Peyto’s strategy remains the same: control the things that we can control while mitigating the risks in the things we don’t — that’s commodities. We believe that’s a winning recipe that provides long-term returns to shareholders and it brings some calm in a volatile commodity market. Okay, I imagine there’s some questions, Marvin, so perhaps we can go to the phones if there’s anybody waiting. If not, we can switch to some stuff that came in overnight. Either way,
OPERATOR
I’m going to conduct the question-and-answer session. As a reminder, to ask a question, you will need to press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while we compile the Q&A roster. And our first question comes from the line of Travis Wood of NBC Capital Markets. Your line is now open.
Travis Wood (Analyst at NBC Capital Markets)
Yeah, good morning, guys. Question I think is going to be for Riley, but could you just share some of the kind of details around what’s driving the outperformance and the nuances within the completions at Brazeau and how that can be fully leveraged, or what from that Brazeau program you’re leveraging into the Sundance Cardium for the remainder of this year, into next year.
Riley Frame (Chief Operating Officer)
Yeah, you bet. Thanks, Travis. Yeah. So in Brazeau, we’ve kind of evolved that design over a period of a couple years now, where we started off with a more conventional open-hole stimulation ball-drop into a cemented system and then into now what we’re doing is a coil-shiftable system. And that’s really allowed us to maintain a stimulation intensity while we’ve been able to drill these wells longer, rather than limiting out on sort of how many balls we can drop through an open-hole system.
And so that’s obviously translated into a higher stimulation intensity, roughly 20% higher. It’s longer laterals, roughly 75% longer than what we’ve done in the past. And so those two things have really added up to where we’re seeing this improved performance as well as this improved per-unit cost that we’re getting per meter of lateral that we’re drilling. So as we pivot to the Sundance Cardium, we’re trying to apply what we can of that. The first pad that we completed there, we sort of stuck with what we knew, if you want to call it that. We did an open-hole ball-drop system, so we drilled those wells to a length that was conducive to using an open-hole system. But as we go forward, I think we basically were kind of completing those wells at the same time that we were testing the coil system in Brazeau.
We’ve since gained quite a bit of confidence in that system and feel like that would be an appropriate system to take to Sundance, which kind of unleashes another level of being able to go longer. So as we step forward in Sundance here, I think we’ll see these wells get pushed out over 2,500 meters. We’ll be able to maintain that stimulation intensity by virtue of using the coil system. And, you know, as we push forward here, I think, you know, what we’re seeing today is sort of that 11% reduction in D&C cost per meter horizontal, you know, could move even further north to, say, 15% to 20% and improvement in performance as we step out to, you know, almost two times as long as we drilled historically in that area. So I think all that will add up to some, you know, continued improved results from both the performance and cost perspective as we step forward with the Sundance program.
Travis Wood (Analyst at NBC Capital Markets)
Okay. Appreciate the color, Riley. I’ll turn it back.
JP Lachance (President and Chief Executive Officer)
Yeah. So, you know, just to sum up there, this isn’t rocket science. You know, others are doing this. This isn’t something brand new to Peyto. We’re just refining it a little bit to make sure it works within our system. Simple as that. So another question,
Travis Wood (Analyst at NBC Capital Markets)
I guess just as you say that, JP, you know, you mentioned it’s not rocket science but the rate of change in that well performance suggests otherwise. So is it in that rate of change then from kind of status quo to the Brazeau completion move to show that shift in the curve — was that three-well pad — have you been able to isolate? Was part of it just the structure of the rock on that particular pad? Or do you think it’s all driven by that change of completion from Brazeau to Sundance?
Riley Frame (Chief Operating Officer)
Yeah, I think it’s a combination of things. There’s obviously a reservoir component to it for sure, but there is, I think, a fairly material component that is driven by us drilling 50% longer and then increasing our stimulation intensity by roughly 20% as well. So.
Travis Wood (Analyst at NBC Capital Markets)
Okay. Yeah. Yeah. Okay, perfect. Thanks, guys.
OPERATOR
Thank you. Thank you. One moment for our next question. Again, as a reminder, to ask a question you’ll need to press star 11 on your telephone. Our next question comes from the line of Chris Thompson of CIBC. Your line is now open.
Chris Thompson (Analyst at CIBC)
Yeah, good morning. Thanks for taking my question, JP. I’ll start on the budget. So I actually get to the same numbers as you on an exit rate of 157 for next year, and that would imply an exit rate of 150 for this year. So, you know, if I draw a straight line between those two, it would have you averaging 153 and a half on the year and that’s where the Street is as of this morning. So just wanted to clarify that’s the right way to be thinking about your production for 2027?
JP Lachance (President and Chief Executive Officer)
Yeah, I mean you got the numbers to start and endpoint correct. But as we — as everybody I think should know better — the way Peyto’s, and it happened this quarter and last quarter, production tends to fall a little bit through the middle of the year and then we ramp up with the back half of the year. And it’s not so much the increase in rig counts or anything like that, it’s more just the nature of the beast. When we’re talking about bringing new production on the front end of the year, it declines a little bit as we can’t keep the activity going during breakup.
So naturally Q2 and Q3 have a fall-off effect on production. So, you know, I think we’ve been pretty good at modeling that behavior in our slides. It kind of shows that in our sort of future slides on Slide 24, particularly, where we show that sort of dip. And it’s pretty common for us to do that. So I think I would caution you not to draw a straight line from start to finish and actually show that little dip in the middle that we typically have almost every year of production.
Chris Thompson (Analyst at CIBC)
Okay, got it. Thank you for that color. And then just on the Cardium well design discussion, on your Sundance slide, just wanted to ask you guys about the steeper decline rate exhibited by those 2026 wells compared to the average prior. Is that — you know, is there a reason behind that? You know, compared to Brazeau, it looks like those declines are actually pretty parallel to previous vintages. So what’s driving the difference between those two areas?
JP Lachance (President and Chief Executive Officer)
Go ahead, Riley.
Riley Frame (Chief Operating Officer)
Yeah, I mean, the rock is very different between those two areas. And so I think what you do see in the Wild River area is that the reservoir probably is a little bit tighter up there. And I think that is manifest in slightly steeper declines as we have increased that stimulation intensity. We get that up-front pop, but those wells will come off just a little bit harder than what we see in Brazeau.
Chris Thompson (Analyst at CIBC)
Okay, that’s good to know. And then just on the Wilrich — your 2026 Wilrich returns, they averaged 20% and all the wells looked like they were below the corporate average of 52% on the year. So just in the context of 2027, like, why include Wilrich in the 2027 budget at all if returns are just so weak compared to your other formations?
JP Lachance (President and Chief Executive Officer)
One of the things you got to remember about the Wilrich is that it’s a formation that exists pretty much across our land base everywhere. And it provides us with information as we drill down into it. So although it doesn’t get its due of some of the returns from the other formations, particularly the Notikewin, we get that look on the way down. And so it’s always been a staple of our program. We can’t drill all of our best wells all at once, or we end up overloading a system, for example, or we end up having too much risk on one formation.
So this is another risk mitigating tool that we have and that’s on the way we develop our drilling program. And we also can’t be on top of each other when we’re drilling wells either — that becomes issues around frac communications, but we’re drilling all kinds of things like that. So the Wilrich will always be a staple of our diet. We continue to push hard on trying to improve its economics through length, through intensity, you know, whatever it takes to do that.
It doesn’t always work out, but it’s always going to be a steady part of our diet because it’s deep and we get to see the other things that are on the way down. Does that make sense?
Chris Thompson (Analyst at CIBC)
Yeah, no, that’s fair. I guess, like, just sticking on the Wilrich, but maybe this applies to any of these: like your Slide 19 IRRs at $3 a GJ compared to your Slide 22 half-cycle IRR at $3 a GJ — the Wilrich you show there, 82% versus actual — and I’m trying to understand why is there a difference between the IRRs you’re showing on Slide 19 versus the IRRs that you talk about being in your inventory.
JP Lachance (President and Chief Executive Officer)
One big difference actually — on the slide on 22, they’re half-cycle numbers just to be able to compare apples to apples across, and the other ones are full cycle. So that does have an impact on the numbers for sure. This is what we aspire to do on the slide on Slide 22 — this is what we think we can do, this is what we have in our program. But we don’t hide the realities of what the outcomes are in Slide 19, of course. Right. So that’s really the difference.
Am I missing something?
Chris Thompson (Analyst at CIBC)
So, but the difference — the outcome on 19 — because from what I can see, it’s the same price stack, right. So is it just that the drill costs came in higher than expected in the portfolio or rates were different or, like, you know, just what’s the color behind the delta there?
JP Lachance (President and Chief Executive Officer)
So the $1.3 million is added to each of those wells in Slide 19. That gives you the full cycle. So it’s a substantial amount of incremental capital, first of all, so you can’t lose sight of that. And I would say the other element here is, of course, you know, we don’t know going into a program — we’re going to be selective on the wells we intend to drill. So they might have a slight higher IRR expectation, which is what we see on Slide 22, than what we actually get on Slide 19.
The reality is Slide 19 shows a pretty good rate of return full cycle. I think that’s the thing to take away from this.
Chris Thompson (Analyst at CIBC)
Yeah. No, understood. Thanks for the color. I’ll hand it back.
JP Lachance (President and Chief Executive Officer)
Okay, thanks.
OPERATOR
Thank you. I’m showing no further questions at this time. I’ll now turn it back to JP Lachance for closing remarks.
JP Lachance (President and Chief Executive Officer)
Okay. Thanks for joining us. I have nothing more to add to this other than we’ll see you next year or maybe sooner. Thank you.
OPERATOR
Thank you for your participation in today’s conference. This does conclude the program. You may now disconnect.
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