Peyto Exploration & Development Corp.

Thank you for standing by, and welcome to PATO's third quarter 2025 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker 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. To remove yourself from the queue, you may press star 11 again. I would now like to hand the call over to President and CEO, J.P. Lachance. Please, go ahead.

Thanks, Lateef. Good morning, folks, and thanks for joining PAYTO'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 at 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, Tar Burdick, our VP of production, Mike Collins, our VP of marketing, Eric Sember, our VP of land and business development, Christy Rafus, our VP of finance, and Michael Reese, our VP of geoscience. Before we discuss the quarter on behalf of this group here, the management team, I'd like to sincerely thank the entire BATO team, both here in the office and in the field, were their contributions to yet another strong quarter. And we had a busy quarter that'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. Properly, production per share was up 5% compared to Q3 last year, relatively flat quarter-over-quarter production at approximately 130,000 BWs a day. But our cash costs 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 costs due to some production dilution. That's absolute costs as well. ECO 7a prices averaged a mere $0.94 per GJ, or about $1.08 per MCF when you account for the heat 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 3.3 times that of ECO 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 by 29% from Q3 last year, or 26% on a per share basis. We also achieved a top-tier operating margin of 72%, with a profit margin of 29%, and which, at the end of the day, we feel is 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, and that's mainly due to the addition of a Sundance compressor station, the addition of a fifth rig later in the quarter, and the old man 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 venture price. 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 old man 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 a drilling program shifted to the potent Nauticuid flare and blue sky 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 advertise individual well rates, but we expect that the wells that we just drilled in the second half of 2025 will perform 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 deploy to achieve them, and we expect that these balls 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 four years. We rolled in what was left of the term loan that we put in place for the Repsol acquisition. So our new revolving credit facility now stands at $1.05 billion, of which 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 nine years. When you take all this together, it provides Payto with a strong liquidity position to execute a business plan. It also shows the support of our lenders to Payto's business plan and to our strategy. I mentioned that we shut in some production in September, not because we were exposed to low eco-prices. Our hedging and downstream diversification protected us from that, but because it made sense to have someone else pay us to take their gas, which we then used 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 ACO, and that's net of the cost to get to those markets. Our physical and synthetic service to Henry Hub, Chicago Dawn, Parkway, Ventura, 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 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 five 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 five rigs and aim for the high end of the guidance, if that makes sense. And this plan is consistent with our low outlook on natural gas prices in 2026. The preliminary program has 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 de-bottom 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 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's an excellent quarter. And as we look forward, we're 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 cost that we control as low as possible while protecting the revenues in the near term with our disciplined hedging strategy and de-risking our sales markets to gas demand regions. This has 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 a little support from our federal government to the industry, and I think PAYTO is well-positioned to take advantage of these exciting times. Okay, I think there's probably some questions, Lateef. Perhaps we can move the phone if there's anybody waiting. If not, I do have some questions that have come in through email overnight.

Thanks, sir. As a reminder, to ask a question, you will need to press star 1-1 on your telephone. To remove yourself from the queue, you may press star 1-1 again. And, sir, I don't show any questions at this time.

Yeah, I will go to some questions I've received via email. This one comes from Chris Thompson of CIBC. He couldn't make the call here this morning. One of his questions is, would Pato continue to hedge gas volumes on forward strip given ACO 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 ACO? So I'll answer the first part of that. I normally would look to Mike. Mike's also got some I had some trouble with his voice this morning, so I'll try and do my best. Mike, you can squeak in if I miss an important point. But I think when we look at, you know, the business, we've always run the business, you know, prudently. And I think when we think about the business of hedging, you know, we're going to continue to be, you know, our discipline risk management program. We're going to navigate the stormy waters of ACO with care. You know, we know this is a volatile market, so our hedging strategy is 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 what 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 We don't change our strategy year over year around that. I guess we have some minimums that we'd like to accomplish, Mike. And I think that's, you know, obviously it's minimum prices that we want to see. So we recognize that, you know, 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 and 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 are we thinking, and how will 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's relentless pursuit of reducing those costs. The other one is just naturally interest costs will come down as we take down debt. Over the next year, interest costs will come down on a pre-unit basis, but maybe, Todd, do you want to elaborate on, we've got some for next year on our facility capital. Maybe you could 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, you want to comment on the operating costs?

Yeah, 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, with off-ex dilution just through, you know, 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 labour 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, you know, with those two things and sort of, I guess, our ongoing little pieces that we work on, we expect to see, you know, a pretty good drop, like you say, around 10% over next year versus what we've seen so far this year.

See you next time. I see there's a question there. Do you want to go to the phones there, please, Lateef?

Yes, sir. Please stand by. We have a question from the line of Amir Arif of ATB Capital. Please go ahead, Amir.

Thanks. Good morning, guys. Just had a quick question on that fifth rig. I think if I heard you right, the capital budget, it's essentially in the year for half a year. I'm just curious. What kind of spot gas price you'd 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 rates extended from half a year to full year?

Yeah, so I think the difference of our capital program for next year than this past year is that we're going to run out of load a little bit more. I'll get Rodney to speak to what that means, but essentially what we're suggesting. We were very happy, first of all, with rigging out to operate. So we feel like keeping it running. Last year, we had a window rig out to do, sorry, a rig on a window, had to drill a couple of holes in that, but it couldn't stay there because we would have filled up that plant and couldn't really effectively use it. But we're down in finance 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 at The price trigger, you know, I think there's so much more than just the price. It's what have we been able to hedge? What have we, you know, 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 five rigs going all year round, that all throughout the whole year, that's the high end of the guidance, essentially. So removing it somewhere in the middle of the year, should we decide to, would be, you know, would get us towards a big point, I would suggest. But, Bradley, do you want to talk about the complexion of the program and maybe how it's loaded?

Yeah, I mean, the complexion of the program from sort of an area, as BC's perspective, is going to be very similar to what we did this year. And to the ETC and non-EC capital allocation is very similar. But as it pertains to sort of the capital program for the year, as we're moving towards that midpoint, we'll see it being sort of a 55% capital front end, 45% capital back end loading. And then, yeah, depending on how the year goes and, you know, 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 back in with the mid-three.

So the production profile will then, you know, sort of look that in similarity as opposed to in the past we've had more of a, you know, a decreasing production profile in the sort of middle quarters because of, activity, and 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'd see in our corporate presentation materials for 26. So if that helps.

Absolutely, that helps, JP. And then just a follow-up question, just 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. There are optimizations with plants. Those are the ones that will typically help with that, other than the production growth itself, you know, considering. But we were stunned a little bit in Q2 as we didn't expect the 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 wealth fund. That's property tax. And that's 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'll be the projects that Todd just discussed. Typically, costs go up in Q1 because it's cold and 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, Tom.

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 off-ex, so we've only got 35% of that off-ex that we are really able to play with. When you look at 50 cent off-cost, that means you're talking 15-16 cents 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 min-piece or 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 54 cents, or 10% reduction from your current cost of 51 cents?

I'd say the all-in cost for the year, you know, year over year. We don't have four over four in this top one to call, right, like I just mentioned, because it can vary. So year over year.

Okay, sounds good. Thank you.

Okay, I have another question. 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 that we'd like to highlight. It was obviously, what was it, 2.6% for the boarder. I just want to ask Tavis 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 community.

Yeah, JP, there are a few factors that contributed to the low royalties for the quarter. Firstly, low ACO again. We were $0.90 on a 7A basis, I think, or $0.94. I think ACO was $0.60 for GJ. And ACO 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 ACO. So we're getting really strong prices in the US Midwest, in Dawn, Henry Hub. And those additional revenues that we're getting really aren't royalty the same as the ACO stuff, right? That's right. Next would be increased gas cost allowance credits. Those went up in Q2, and we're going to see those for the next three or four quarters. And then we also had lower NGL royalties from the declining 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 half percent.

Well, we haven't encumbered our lands with other, besides Crown royalties, we're not encumbered with other royalties, and 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 overrunning royalties to others. And that's about half a percent, you said, roughly, run rate?

Yeah.

So what's our overall run rate going forward here? Do you think there's a reasonable expectation given this trend?

Yeah, I think for Q4, we're going to be in the 4% to 4.5% range. Next year, though, with the price of Strip, we'd probably be 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.

Yes, sir. Please stand by. Our next question comes from the line of Mike Bill of Davenport. Your line is open, Mike.

Thank you. 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 out in the future if that's where you're going. 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. That's the big market that would be affected. In Canada here, we're working towards more export capabilities to help our local markets. And that's encouraging as we think forward beyond just this year, we've got LNG Canada slowly getting going here, but that 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.

Thank you.

Thanks, Mike. 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.