Q3 2025 Peyto Exploration & Development Corp Earnings Call
Speaker #1: 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.
Speaker #1: To remove yourself from the queue, you may press *11 again. I would now like to hand the call over to President and CEO Jean-Paul Lachance.
Speaker #1: Please go
Speaker #1: ahead. Thanks, Latif.
Speaker #2: 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.
Speaker #2: Here in the room with me is Riley Frame, our COO, Travis Carlson, our CFO, Lee Curran, our VP of Billing and Completions, Todd Burdock, our VP of Production, Mike Collins, our VP of Marketing, Derek Zember, our VP of Land and Business Development, Chrissy Rafas, our VP of Finance, and Michael Reese, our VP of Geoscience.
Speaker #2: 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.
Speaker #2: 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.
Speaker #2: 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.
Speaker #2: And most recently, we extended our credit facility. And that's just to name a few things. Corporately, production per share was up 5% compared to Q3 last year, relatively flat quarter over quarter production at approximately 130,000 BOEs a day.
Speaker #2: 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.
Speaker #2: And that's not just unit costs due to some production dilution. That's absolute costs as well. ICO-7A prices averaged a mere 94 cents per GJ, or about $1.08 per MCF when you account for the heat content of our gas.
Speaker #2: For the quarter, our strong hedge book added $87 million in gains, or about $1.38 per MCF for gas, and our marketing diversification contributed another $1.11 per MCF. This yielded an all-in realized natural gas price of $3.57 per MCF, which equates to about 3.3 times that of ICO for the quarter.
Speaker #2: Putting all these elements together resulted in funds from operations of nearly 200 million dollars, or 98 cents per diluted share. And that's up from 29, up by 29% from Q3 last year, or 26% on the per share basis.
Speaker #2: 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 after all.
Speaker #2: right? And it's those profits that we can return back to our shareholders in the form of dividends, which we paid out 33 cents per share in the quarter, or a total of 66 million It's generating profits, dollars.
Speaker #2: $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 Old Man plant, we spent turnarounds.
Speaker #2: The 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.
Speaker #2: 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.
Speaker #2: Can I just 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.
Speaker #2: 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.
Speaker #2: And our drilling program shifted to the potent, not acute, and flare and blue sky species in the third quarter, and we're now drilling and completing what we expect will be the most productive wells of the 2025 program.
Speaker #2: We don't advertise individual well rates, but we expect that these wells, which we just drilled in the second half of 2025, will outperform those from earlier in the year. As such, our full-year vintage production curve should look a whole lot like 2024.
Speaker #2: The complexion of the species in the second half really relates to the half as compared to the first half. Of course, it isn't just the rates that matter.
Speaker #2: 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.
Speaker #2: 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 target of 140,000 BOEs per day and very comfortable reaching our exit for December, which correlates to the midpoint of our guidance on capital spending.
Speaker #2: Subsequent to the third quarter, we renewed and extended our credit facility for another four years. We rolled in what was put in place for the Repsol acquisition.
Speaker #2: 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, so our new revolving credit facility now stands at $1.05 billion, of which we were drawing $745 million at the closing of that extension.
Speaker #2: 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 Peyto with a strong liquidity position to execute our business plan.
Speaker #2: 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 ICO 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.
Speaker #2: Our diversification to other markets allowed us to gain a premium price of $1.11 per MCF, as I mentioned earlier, over ICO, and that's net of the cost to get to those markets.
Speaker #2: Our physical and synthetic service to Henry Hobb, 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.
Speaker #2: We've released our preliminary capital budget for 2026. We plan to invest between $450 million to $500 million in capital next year to drill between 70 to 80 net wells.
Speaker #2: 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 percent corporate production decline over the year.
Speaker #2: 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.
Speaker #2: And the capital profile will be a little more front-end loaded than in past years. We can apply the brakes and slow down the program in the second half if prices or the business environment warrants it.
Speaker #2: 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.
Speaker #2: 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 debottleneck field gas gathering systems to accommodate new drilling.
Speaker #2: 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 taught to expand on that with some details later.
Speaker #2: 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.
Speaker #2: So, in closing, we think it's an excellent quarter. As we look forward, we're well positioned to grow modestly, by 5 to 10 percent, with enough cash flow not only to fund the capital program but also to return dividends to our shareholders.
Speaker #2: 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 de-risking our sales markets to gas demand regions.
Speaker #2: 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 buildouts in North America.
Speaker #2: 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.
Speaker #2: And I think Peyto is well positioned to take advantage of these exciting times. Okay, I think there's probably some questions to get to, so if there's anybody waiting, please let me know.
Speaker #2: If not, I do have some questions that have come in through email and overnight. Thanks, sir. As a reminder, to ask a question, you will need to press *11 on your telephone.
Speaker #2: To remove yourself from the queue, you may press star 11 again. And, sir, I don't show any questions at this time.
Speaker #1: Yeah, we'll go to some questions I've received via email. Although this one comes from Chris Thompson of CIBC. He couldn't make the call here this morning.
Speaker #1: One of his questions is: would Peyto continue to hedge gas volumes on the forward strip, given that a global basis remains wide for the foreseeable future?
Speaker #1: 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 ICO?
Speaker #1: So, 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.
Speaker #1: Mike, you can squeak in if I miss an important point, but I think when we look at the business, we've always run the business prudently.
Speaker #1: 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 ICO with care.
Speaker #1: We know this is a volatile market, so our hedging strategy does not plan to change. As everyone knows, we have the guardrails.
Speaker #1: 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.
Speaker #1: Increased production discipline. I can't speak to, I don't know about the 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.
Speaker #1: 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.
Speaker #1: Mike, and I think that's obviously some 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.
Speaker #1: We're still taking 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.
Speaker #1: In the near future, another question Chris had was on our 2026 goals for cash costs, and what we're thinking and how we achieve those goals.
Speaker #1: 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.
Speaker #1: It's a relentless pursuit of reducing those costs. The other one is that interest costs will come down naturally as we take down debt over the next year.
Speaker #1: Interest costs will come down on a per-unit basis. But maybe, Todd, do you want to elaborate on? We've got some plans for next year on our facility capital.
Speaker #1: Maybe you can tie that into maybe how that helps us reduce our costs. And 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.
Speaker #1: But maybe, Todd, do you want to comment on the operating...
Speaker #1: costs? Yeah, sure.
Speaker #3: So, obviously we have a number of facility and 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. This will help, obviously, with OPEX dilution just through the increased production.
Speaker #3: 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.
Speaker #3: Which we're starting to really see bear 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.
Speaker #3: Weather has helped a little bit, but obviously through the winter months, when pricing typically goes up during this time, we're kind of seeing things hold flat, which is a good sign in the chemical market.
Speaker #3: 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 the next year versus what we've seen so far this.
Speaker #3: year. Okay, thanks, Todd.
Speaker #1: I see there's a question there. Do you want to go to the phones, then, please?
Speaker #1: Latif? Yes, sir.
Speaker #2: Please stand by. We have a question from the line of Amir Arif of ATB Capital. Please go ahead, Amir.
Speaker #4: Okay, thanks. Good morning, guys. I just had a quick question on the fifth rig. I think if I heard you right, the capital budget is essentially for half a year, and I'm just curious what kind of spot gas price you need to keep it for the whole year. If you do, how much additional capital can we think about, or additional production can we expect if the rig is extended from half a year to a full year?
Speaker #1: Yeah, so I think the difference in our capital program for next year compared to this past year is that we're going to run in load a little bit more.
Speaker #1: And I'll maybe get Roddy to speak to what that means. But essentially what we're suggesting, we were very happy, first of all, with bringing it out to operate.
Speaker #1: So we feel like keeping it running last year, we had a window to rig out to do. Sorry, we got a rig on a window, had to drill a couple of wells and all that, but it couldn't stay there because we would have filled up that plant and couldn't really effectively use it.
Speaker #1: But 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.
Speaker #1: 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?
Speaker #1: What have we, where 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's all throughout the whole year, that's the high end of the guidance, essentially.
Speaker #1: So, removing it somewhere in the middle of the year, should we decide to, would get us towards a midpoint, I would suggest.
Speaker #1: But Roddy, do you want to talk about the complexion of the program and maybe how it's loaded?
Speaker #3: 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.
Speaker #3: And this may be related to the ECP and non-ECP capital. Allocation is very similar but as it pertains to sort of the capital program for the year as we're aiming towards that midpoint in practice, we'll see it being sort of about 55% capital front end, 45% capital back end loading.
Speaker #3: And then yeah, depending on, I don't know how the year goes and obviously prices play 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.
Speaker #3: So the production profile will then sort of look that 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 and now we're going to probably be a little more build that production.
Speaker #3: 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.
Speaker #2: Okay, absolutely. No, that helps, JP. And then just a follow-up question 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?
Speaker #2: 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 progresses?
Speaker #2: unfolds? Well, we have some projects that
Speaker #1: We have planned optimizations for 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 didn't expect government costs to now be roughly 30% of our operating costs.
Speaker #1: Which is significant, right? That's the AER fees, the fees to pay the orphan well fund, property tax, and carbon tax. We didn't have enough in our budget for the property tax in Q2, so we went up in Q2.
Speaker #1: 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 in Q1 because it's cold, and we use more chemical, and costs decline if the rest of the year progresses. That's what I think you can expect on the profile.
Speaker #1: Go ahead,
Speaker #1: Todd. Appreciate that.
Speaker #4: On your point, Todd, on government costs and fixed costs in general, which is a lot harder to drive down yearly. They're 60% to 65% of our total offhand.
Speaker #4: So, we’ve only got 35% of that offhand that we can really play with. And when you look at 50 cents off costs, 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 fees, or things like that.
Speaker #4: that. Okay.
Speaker #2: 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 a 10% reduction from your current cost of $0.51?
Speaker #2: cents? I'd say the all-in cost for the
Speaker #1: Year over year, we don't go to the top one to call, right? Like I just mentioned, because it can vary. So, year over year.
Speaker #2: Okay. Sounds good. Thank
Speaker #2: you. Okay.
Speaker #1: 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.
Speaker #1: 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.
Speaker #1: One of the lowest, I think, in the...
Speaker #3: 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.
Speaker #3: I think we're at 94 cents. I think ACO was 60 cents for GJ. And ACO is really what drives the Alberta reference price that the Crown uses to charge us royalties.
Speaker #3: And then secondly, we have a lot of our volumes diversified away from ACO. So we're getting really strong prices in the U.S. Midwest, in Dawn, Henry Hub.
Speaker #3: And those additional revenues that we're getting really aren't royalties the same as the ACO stuff, right?
Speaker #1: Right, that's
Speaker #1: right. Next would
Speaker #3: 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.
Speaker #3: 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.
Speaker #3: percent. So we haven't encumbered our
Speaker #1: Lands with other than Crown royalties, but not encumbered with other royalties. I think that's a testament to the way we run the business.
Speaker #1: You paid me an hour. Pay me later. In this scenario, I guess we 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.
Speaker #1: And that's what half a percent you said roughly around, right?
Speaker #3: Yeah. So what's our overall run rate going forward here? Do you think it was reasonable?
Speaker #1: 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're probably modeling more like 5% to 6%.
Speaker #1: Right
Speaker #1: on.
Speaker #4: So back to the
Speaker #4: Phones. If there's another call on the phone, we can take that.
Speaker #2: Yes, sir. Please stand by. Our next question comes from the line of Mike Bill of Davenport. Your line is open, Mike.
Speaker #4: 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.
Speaker #4: 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?
Speaker #4: pricing? Well, I
Speaker #1: I guess you're referring to the fact that you might have too much LNG, and it gets backed up onto the continent. Of course, that would have a negative impact on pricing out in the future, if that's where you're going.
Speaker #1: 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.
Speaker #1: So, I mean, that's the big market, right? It'll be affected. In Canada here, we're working towards more export capabilities to help our local market.
Speaker #1: 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.
Speaker #1: So it's good for the overall future out there. But that's one of the reasons we think about hedging and we think about taking that risk down. We want to be exposed to different markets so that we can weather those storms, and we feel that they'll be shorter term.
Speaker #1: And we can weather those storms when we've had an active and continue to have an active hedging program. We still believe gas is going to be one of the most volatile markets, and we want to be able to smooth those revenues out, right?
Speaker #1: Smooth out that volatility.
Speaker #4: Right. Okay. Thank you.
Speaker #1: Thanks, Mike.
Speaker #3: Okay. Any more questions? On the line?
Speaker #2: I show no further questions from the phone lines at this time.
Speaker #3: Okay. Well, thank you very much for participating in the call. I appreciate the engagement and the involvement, and we'll see you next time.
Speaker #3: Okay. Well, thank you very much for participating in the call. I appreciate the engagement and the involvement. We'll see you next year. Ladies and gentlemen, this concludes today's conference.