Thank you for standing by, and welcome to Peyto'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 one one on your telephone. To remove yourself from the queue, you may press Star one one again. I would now like to hand the call over to President and CEO, J.P. 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 Collins, our VP of Marketing; Derek Sember, our VP of Land and Business Development; Chrissy Raffas, 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 Peyto team, both here in the office and in the field, for their contributions to yet another strong quarter. We had a busy quarter that has 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. Most recently, we extended our credit facility. That is just to name a few things. Corporately, production per share was up five percent compared to Q3 last year, with relatively flat quarter-over-quarter production at approximately 130,000 BOE a day. Our cash costs of CAD 1.21 per MCFE, or CAD 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. That is not just unit costs due to some production dilution.
That's absolute costs as well. AECO 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. Our strong hedge book added $87 million of gains, or about $1.38 per MCF for gas. 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 AECO for the quarter. Putting all these elements together resulted in funds from operations of nearly $200 million, or $0.98 per diluted share. That is up by 29% from Q3 last year, or 26% on a per-share basis. We also achieved a top-tier operating profit margin or operating margin of 72%, with a profit margin of 29%, 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 CAD 0.33 per share in the quarter, or a total of CAD 66 million. We spent CAD 126 million of capital in Q3, up from previous quarters. And 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 CAD 20.5 million, bringing our year-to-date net debt repayment to CAD 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 old man turnarounds and some gas that we elected to shut in when prices went negative. 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. 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 advertise individual well rates, but we expect that the wells that we just drilled in the second half of 2025 will outperform those from earlier in the year, such that our full-year vintage production curve should look a whole lot like 2024. 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. We expect that these wells will rank as some of our highest rates of return projects this year. 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 BOE 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 CAD 1.05 billion, of which we were drawn CAD 745 million on closing of that extension. We still have approximately CAD 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 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 protected 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 CAD 1.11 per MCF, as I mentioned earlier, over AECO. That is 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. We expect them to continue to contribute meaningfully into 2026 based on the current strip.
We've released our preliminary capital budget for 2026. We plan to invest between CAD 450 million-CAD 500 million of capital next year to drill between 70-80 net wells. This program should add between 43,000-48,000 BOEs per day by next December and more than replace our estimated 26%-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 2026, 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. This plan is consistent with our 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 deballing 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. Maybe we will 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.
In closing, we think it was an excellent quarter. As we look forward, we're well positioned to grow modestly, 5-10%, 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 loads in North America and the increasing appetite for power generation from gas in both the U.S. and Canada. Heck, it looks like we've even got a little support from our federal government to the industry. I think Peyto is well positioned to take advantage of these exciting times. Okay, I think there's probably some questions, Latif, perhaps from the room at home 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 one one on your telephone. To remove yourself from the queue, you may press Star one one again. Sir, I do not 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 Peyto continue to hedge gas volumes on the forward strip given AECO basis remains wide for the foreseeable future? 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? I'll answer the first part of that. I normally would look to Mike here. Mike's also got 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. I think when we look at the business, we've always run the business prudently. 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. 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. I do know that we don't change our strategy year over year around that. I guess we have some minimums that we'd like to accomplish, Mike.
I think that's obviously some minimum prices that we want to see. 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, and we'll continue to do that. 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 how we'll achieve those goals. Maybe I'll turn that over to, 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 a 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. Maybe, Todd, do you want to elaborate on OPEX? 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. I would say all in all, the target that we're looking at for cash costs for next year should be somewhere around 10% reduction, excluding royalties, of course. Maybe, Todd, do you want to comment on the operating costs?
Yeah, sure. 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 OPEX dilution just through the increased production. 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. 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. 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.
Okay, thanks, Todd. I see there's a question there. Do you want to go to the phones there, please, Latif?
Yes, sir. Please stand by. We have a question from the line of Amir Arif of ATB Capital Markets. 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 am just curious what kind of spot gas price you need sort of to keep it for the whole year. 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 a year to full year?
Yeah. I think the difference of 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. Essentially, what we're suggesting, we were very happy, first of all, with rigging out to operate. We feel like keeping it running. Last year, we had a window to rig out to do, sorry, a rig on a window, had to drill a couple of wells and stuff. It could not stay there because we would have filled up that plant. We could not really effectively use it. We are down in Sundance right now. Things are going well. We would like to keep it running. We are going to do that. That just changed the complexion of the loading. Maybe we will 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 are our cost situations? There's a lot that goes into that. I wouldn't say there's necessarily a price trigger. If we kept the five rigs going all year round, that's all throughout the whole year. That's the high end of the guidance, essentially. Removing it somewhere in the middle of the year, should we decide to, would get us towards the midpoint, I would suggest. Riley, do you want to talk about the complexion of the program and maybe how it's loaded?
Yeah. 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. I think we alluded to the DCP and non-DCP capital allocation is very similar. As it pertains to sort of the capital program for the year, as we're aiming towards that midpoint of guidance, we'll see it being sort of a 55% capital front-end, 45% capital back-end loading. Then, yeah, depending on how the year goes and obviously price is 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 the midstream, so.
The production profile will then sort of look at 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'd see in our corporate presentation materials for 2026. If that helps.
Okay. Absolutely. No, that helps, JP. Just a follow-up question. Just in terms of the cadence of the operating cost improvements you're thinking for 2026, is it more tied to the looping projects at Sundance? 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 optimizations of the plants. Those are the ones that will typically help with that. Other than the production growth itself, considering that we were stung a little bit in Q2 as we did not expect to, government costs now are roughly 30% of our operating costs, which is significant, right? That is the AER fees. That is the fees to pay the Orphan Well Fund. That is property tax. That is carbon tax. We did not have enough in our budget for the property tax in Q2, so we went up in Q2. I do not know what surprises are around the corner. As far as what we control on that side, it will 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. That's what I think you can expect on the profile. Go ahead, Todd.
On your point on government costs and fixed costs in general, which is a lot harder to drive down yearly. They are 60-65% of our total OPEX. We have only got 35% of that OPEX that we are really able to play with. When you look at 50 cents off costs, that means you are 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 fees or things like that.
Okay. Just to clarify, should we be thinking about a 10% reduction to your average cost from this year, which is CAD 0.54, or a 10% reduction from your current cost of CAD 0.51?
I'd say the all-in cost for the year, year over year. We don't want the 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. 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 Todd 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, I think, in the industry.
Yeah, 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. Secondly, we have a lot of our volumes diversified away from AECO. We are getting really strong prices in the US Midwest, in Dawn, Henry Hub. Those additional revenues that we are getting really are not royalty the same as the AECO stuff, right?
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. We also had lower NGL royalties from the declining WTI and NGL prices. Lastly would be just we have lower other royalties. We haven't done any wide sweeping overriding royalty deals on our lands. Our other royalties are probably less than 0.5%.
We have not encumbered our lands with other, besides Crown royalties, but not encumbered with other royalties. I think that is 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. I guess we always think of royalties as not being a controllable cost. In that sense, it would be if we were to burden our lands with a bunch of overriding royalties to others. That is about 0.5%, you said, roughly, run rate?
Yeah.
What's our overall run rate going forward here, do you think, is a reasonable expectation given the strip?
Yeah. I think for Q4, we're going to be in the 4-4.5% range. Next year, though, with the price of strip, we'd probably be modeling more like 5-6%.
Okay. Right on. 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 B of Davenport & Company. 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 is also some talk of a surplus later in the decade of LNG. Would that ever work against us in terms of North American pricing?
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 US producers have a lot of discipline in that regard to reacting to that with supply cuts and whatnot. 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. 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. It's good for the overall future out there. That is 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. We feel that they will be shorter term. We can weather those storms when we have 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. 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.