Ladies and gentlemen, thank you for standing by. Welcome to Peyto's Third Quarter 2024 Financial Results Conference Call. At this time all participants are in a listen-only mode. After the speakers’ presentation there will be a question-and-answer session. [Operator Instructions] Please be advised that today's conference is being recorded. I would like now to turn the conference over to JP Lachance, President and Chief Executive Officer. Please go ahead, sir. Jean-Paul Lachance: Thanks, Michelle. Good morning, folks, and thanks for joining Peyto's third quarter 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. Present with me to answer questions is Riley Frame, our VP of Engineering and Chief Operating Officer; Tavis Carlson, our VP of Finance and CFO; Lee Curran, our VP of Drilling and Completions; Todd Burdick, our VP of Production; and Derick Czember, our VP of Land and Business Development. To start, I'd like to thank the entire Peyto team, both in the office and in the field for their safe and efficient execution this past quarter. And to put that in context, let me elaborate on their accomplishments with some details here. We had a major turnaround at the Edson Gas Plant in September that was safely executed. And I suspect most people listening have not been involved in one of these, but you should know that there's a terrible amount of work that is conducted in tight spaces around large and often dangerous equipment in a very short period of time. So that requires both great planning and great execution to pull it off, and I'd like to specifically commend the team in Calgary and particularly the folks of the Edson Gas Plant for a job well done. Besides managing production throughout the quarter, we also shut in some significant volumes for short periods when gas prices really fell at AECO. Typically this happens on a Friday, leading into the weekend and it takes coordination with our marketing team and our operations group, both in the office and the field to shut in and then bring back gas back on during these periods. As a reminder, we choose to do this, it's not because we are significantly exposed to the price at AECO. Our hedges and our diversity protect us from that. But it really needs to be opportunistic, especially when prices are negative or near zero. In this case, we purchased or we actually get paid to use someone else's gas to fulfill our physical commitments and save our molecules for better price days. And our thanks to the Peyto team goes beyond the production operations group. We are drilling and completing some fantastic wells these days, and I'll talk a bit about that more later. And everybody in the office plays a role in that from the acquisition of these opportunities in the first place is right through to the execution of the drilling program. These folks, along with the strong leadership we have in the field and our contractors who actually do the work are responsible for our industry-leading costs and cycle time. Okay. Let's get to the specifics of the third quarter, starting with the numbers. Daily AECO prices averaged an incredibly low $0.65 GJ over this period, but Peyto still managed to deliver about $154 million of funds from operations, essentially the same as last quarter on the backs of our disciplined hedging policy and our low-cost operations. And a reminder that our mechanistic hedging program, which yielded us about 4x the AECO daily price this quarter is designed to derisk and smooth out commodity price volatility and gives us predictable revenues to provide confidence to run our capital program, to manage the balance sheet and to pay our shareholders a dividend. Year-to-date, we are essentially net debt neutral, but we expect to further reduce net debt in the fourth quarter with better prices both hedged and unhedged and higher production. Cash costs for the quarter were $1.44 per Mcfe, down from second quarter due to lower royalties and G&A expenses which were offset by higher interest transport and operating costs. The slight increase in operating costs is largely due to the curtailment of production we did in the quarter and some non-capitalized turnaround costs incurred at the Edson Gas Plant. During the quarter, we also shut in – we shut in the sour gas processing and sulfur recovery units at the Edson plant, and we expect to start realizing the associated operating cost benefits in Q4 and beyond. We remain committed to reach the target we set, which is to reduce operating expenses by 10% from Q1 levels by year-end. Peyto continues to have the lowest cash cost in the business and one of the highest operating margins. I think the Peyto's operating margin of 64% screens very well this quarter when compared to our peers, especially considering we're a gas producer. And it's a testament to how we run the business. Okay. Let's talk a bit about the drilling program. We continue to achieve some great well results, not only from the acquired Repsol lands, but on our legacy lands too. The well results from our total program combined to exhibit an average sustained production improvement of about 25% as compared to prior years and comes without increasing our drilling and completion costs year-over-year. This improved well productivity and capital efficiency forms the basis of our expectations for next year's program. Specifically, on the Repsol lands, where we've drilled about half of our total well count in 2024. Average productivity shows a 40% improvement as compared to prior years. This activity has allowed us to essentially to double production from the asset in one year from 23,000 to 46,000 BOEs a day. And this is also impressive considering we deliberately shut in approximately 3,500 BOEs a day of the Repsol based production to save on operating costs and increased plant reliability, particularly at Edson. But not to be outdone, the efficiency has also increased on our legacy lands where we continue to identify new plays. We're 26 years on now since when we started in an area where I call, of course, in Central, in Sundance area which I call Downtown Peyto. I'm referring, of course, to a new prolific Falher channel where we drill a couple of wells, which we hadn't previously recognized and it contains about 20 follow-up locations. During the quarter, we issued a new $75 million private notes at 5.64% for the 10-year term and we'll use them to repay some private notes that were coming due next – in next May. This is the second note refinancing we've closed in the past year, and it's a testament to the support of our lenders to the company and our business plan. On the marketing front, we've been on, we're successful in securing 50,000 GJs a day of TC mainline transportation service to Union Parkway Belt, which is near Toronto or far from Don. This service delivers to an important demand center and it complements our diversification strategy, which is a mix of basis deals marketing arrangements in physical transport throughout North America. This 10-year Parkway contract started in November and uses some of the company's excess Empress transport and it costs about $1 GJ to get ourselves there from Empress. Our 60,000 GJs a day or about 52 million days of gas supply. We've got supply agreement we have to the Cascade power plant kicked in on August 31. Recently, the power plant was down and went some scheduled maintenance, but it's back up and running now. And we think over the long-term, this contract will be greatly beneficial as power demand increases in Alberta with the future prospect of data centers and for AI. As we look forward here in Q4, we continue with an active program. We're drilling and completing wells, and we're not holding on to inventory or DUCs. We believe running an uninterrupted program is important. We can slow down if we need to, but we refer to run a steady program to achieve our cost efficiencies. We recently averaged a new monthly production high of 130,000 BOEs a day in October. This provides us confidence that we're on track to meet or exceed our exit target of 135 BOEs a day which corresponds to the low end of our capital guidance of $450 million. At these production levels, we have minimal AECO exposure, but we will, of course, manage production at prices significantly weaken. Let's talk a bit about the preliminary budget. We've released the preliminary budget for 2025. We plan to spend between $450 million to $500 million of capital next year. It should drill us about 70 to 80 wells. This program should add about 43,000 to 48,000 BOEs a day and more than replaced our estimated 26% to 28% decline for next year. The higher decline rate relates to our plan to bring on a lot of new production here at the end of the year like we've talked about. This increase in decline will be offset by better capital efficiencies from our drilling program which is based on what we've demonstrated so far in 2024. Preliminary program budgets about the same amount of capital for facilities projects as the past year – as this past year. It includes a field compressor project in Sundance, this will be strategically located with some development drilling and intended to move older liquid rich wells to the Edson gas plant where we get better liquid recoveries. And this will also serve to minimize backload in the areas we continue to grow production in Sundance. Our 4-rig program is designed to hold production flat more or less through the first half of 2025 and we believe this will be well timed with LNG start-up in the latter part of 2025 and allows us to assess future gas prices and adjusted plans accordingly. We'll firm up the capital budget in February with our reserve releases, which will also allow us to see how the winter shapes up and if there are any updates to on LNG timing. So in closing, although there's some pressure on natural gas prices in the short-term, we've hedged our bets literally with close to $800 million of fixed revenue for next year. This, along with our cost discipline, will insulate us and allow us to execute our capital plan, pay dividends and pay down some debt in 2025. We always believe we're in the right business with incredible build-out of LNG egress that's coming soon in North America and we should – that should benefit all markets. You combine that with potential increases from North American power demand, and that provides us with some great optimism in the future of the natural gas market. So I can imagine there may be some questions. Michelle, do you want to perhaps go back to the phones to see if there are any questions, anybody lined up to ask a question.

Sure. Thank you. [Operator Instructions] And our first question will come from Chris Thompson with CIBC. Your line is now open.

Good morning, everyone. Thanks for taking my questions. Just on that Falher discovery, I'm wondering what led to the identification of that prospect on your legacy lands? Jean-Paul Lachance: Yes. We're drilling a lot of wells through there, especially when we drill down to the Wilrich level, that's why we like the Wilrich as a sort of a base player because it gives us a lot of information. A lot of these plays that we discovered later on is just simply because you've got more information as you go through, you've got seismic to help you with identify plays, but you also have the actual well results. And so as you continue to go through these and frankly, it allows us with quality of program we've been drilling on the Repsol lands, it allows us to test some of these things that maybe we weren't sure about in the past, and so it gives us an opportunity to go there and test some of these plays, considering how well things have been going for us. Do you want to add anything to that, Riley?

No, I think that covers it pretty well yes. Jean-Paul Lachance: Thanks, Chris.

Yes. And then just as a quick follow-up. Cadence of production growth through the year. I know you indicated second half was sort of where you're awaiting the growth, but perhaps you could just offer us a bit more color on how you're thinking about that? Jean-Paul Lachance: Yes. So I think I mentioned that our decline would be a little higher next year, so we have to offset that. And that's really a product and the fact that we bring in a lot of flush production on year-end, here on year-end. So we'll see where that lands as we move forward. But typically, when you look at our production profiles, we normally more or less stay flat or even drop a little bit through the first half of the year because the declines are on the highest at the front end of the year. So we like to run a steady program, as I mentioned earlier, it's important – really important to understand as we run a steady program, we have to obviously replace a lot higher more decline in the front half of the year. So that's why we normally stay flat. We also have a second quarter also break up and of course, during breakup, we can't be quite as active or we may not be able to get to things like we'd like to with the wet weather. So that sort of drives that slower pace in the first half of the year. And then we would ramp up to aim for those exits based on whatever that decline settles in at and of course, our capital efficiency – assuming we get the capital efficiency that we're describing here, which is both 10,500 whatever the capital program we run, right. So a flat first half of the year, maybe down a little bit as we run through the year and then most of that ramp will come up at the end of the third quarter and to fourth quarter.

Okay. Great. Thank you all. I hand it back. Jean-Paul Lachance: Thank you.

Okay. And our next question will come from Aaron Bilkoski with TD Cowen. Your line is open.

Actually, the perfect follow-up question to the last question. Given that you guys are so well hedged through 2025, is there a commodity price or a scenario where you look to delay some of the plant production additions you outlined for 2025? Jean-Paul Lachance: Well, we tested the model to quite low levels. In fact, I don't know if it gets any lower than what we just went through. But we've tested our business plan rate down to $1 or $1.50, say, on average for the whole year at AECO. And I think in that case, we might hit the lower end of our guidance. And with that, we would still be able to grow and pay down some debt. So I guess there's always a price that you – maybe if it were to go lower than that, we would consider changing up the plan, but we have 70% hedged for next summer, not range. And so I don't see really a scenario where we would pull back significantly. But of course, we know it's right.

Perfect. Thanks. Can I ask a follow-up question about the Cascade power supply contract? Jean-Paul Lachance: Sure.

I guess my question is, is the benefit of that simply being reflected in your realized gas price? Jean-Paul Lachance: Yes, because that contract is confidential, we're careful about what we can disclose around the specifics. So it will – the realized price there will be part of our total I guess, price for the quarter, do you want to elaborate on that?

Yes. So for Q3, we would have picked up the contracts just for the month of September. So one month out of the full quarter. Going forward, we're going to be sitting right into that realized price.

I'll try. I think I know your answer, but would you guys be able to tell me what your realized gas price was in Q3 without the benefit of that contract? Jean-Paul Lachance: So that you can back into the price we got from that? Is that what you're saying? So you tried. No. In time, we'll provide some more clarity on what that looks like. How's that Aaron, and I'll give you that.

That’s perfect. Thanks, guys. Jean-Paul Lachance: Thanks.

[Operator Instructions] And the next question will come from Gerald McCahey with [indiscernible]. And your line is now open.

Thank you. Great quarter, JP and the team. I have a couple of questions. They're quickies though. How would you say you're doing on the presentation that was available at the time of the acquisition started at 123,000 barrels a day? I think when we take out the 2,000 barrels that you took out for this economics, let's start it at 121. In the middle of that presentation, there was a ramp-up October of 2023 through 2026, that got us to 160,000 barrels plus 14% in 2024, 14%, plus 13% in 2025 and plus 13% in 2026. So how would you – how do you feel you're doing against that? And would you still be comfortable with that? That would be first question. Second question, bottom-up is I just would like a little commentary on the hedges. And the first is it appears that the floating rate lock-ins that you have are substantially better than what the current spread is, and I'm talking about like the Henry Hub exposure and stuff like that, that's at $0.93. When I look at where Henry Hub is trading versus AECO, it looks like the spread is well above $0.93, and that's kind of a subtle benefit that a little color would be helpful on. And it looks pretty big, actually. And the other thing I'm interested is the logic behind Parkway. I appreciate it's further diversification, but there's also over the last two reports on the hedging, we also dropped 50,000 a quarter of Henry Hub in two quarters of next year or it's maybe more than that. And the last question was on net debt, we say were flat for the year. This quarter, CapEx and dividends exceeded free funds flow they were $190 million and free funds flow was $55 million. So I'm just curious how we're maintaining that. I don't know if it's working capital changes or what, but just a little comment on that. That's enough questions anyway. Jean-Paul Lachance: Okay. Thanks, Gerry. Hopefully I remember them all I tried to write them down as you were talking, but we'll go – you can ask them again if I miss something here. But to start off on the progress. Yes, we went to the low end of our guidance this year. So we only said we're going to – we plan only spend close to $450 million. So we won't – we will be I think that plot you're referring to would have been on the high side of spending closer to the $500 million. So we still see ourselves getting to $160 million might take another year, but there's an updated plot on Slide 21 of our presentation, we'll give you a sense for what that looks like today. I would say we're doing very well with it. Things have come along very nicely with the acquisition. We're obviously getting the results. So we're quite pleased with the outcomes there. And that growth should be somewhere in the, I think, 5% to 10% range as we move forward, continuing on. The second part of your question was on – I think on the diversification and how we're getting some of the value out of that and why it's so much better than where AECO sits today. I mean when we look at diversification to stay in the hub and get and look for our basis deals, we're doing this several years ahead when the basis is trading at something closer to $1, which is or less, which is where transportation is. So our strategy is to go get that basis out there and then when you can prices more or less at pipe costs. So we're not committing to the long-term physical pipe, but we're getting basically equivalent to that by doing it this way. So there obviously when we – and then in some cases, we're hedging some of that, right? So when you say it disappeared, the 50,000 disappeared, what we did was we hedged Henry Hub to make with one of those diversifications. So some of that diversification to basically fix it up. So that's the main reason for the change in Henry Hub. And then – and also, I think you asked about Parkway, right? Is that right? Yes, Parkway. So the logic on there is, again, just having more diversification to Eastern markets. That can be a premium market and especially in the winter time. So we'd like to have exposure to that. It just fits in there with our other diversification to Don and the middle and the Midwest, U.S. Midwest, we actually sold some of the Emerson service so that we could layer in that piece and get it all the way to Union Parkway for the next – I think it's the next year. Is that right, Tavis? So we've done some of that. Just to make sure that we don't over have too much diversification but we recognize that that's a stronger market than, say, Emerson right now. So that's why we did that. And we're excited about what it could deliver. I mean I think if I think back to what happened in – I think it was February 2021 or was it February 2022, where prices – where there was a freeze-offs in Texas and we had Ventura really ran. And just over a weekend alone, when you're exposed to those markets, you can have a tremendous gain. So last question was on debt. If I recall, net debt, you said something about [indiscernible] payout. Yes, we don't – we run the business for the long-term here. We're not looking at short-term gains. Sometimes we can't bring all the production on in one quarter. So we're spending capital now for the future. We expect to be paying down debt here in the fourth quarter based on the fact that we have higher prices, not only our hedge prices are higher, but also our – the forecast looks better. So plus we have more production. So that is – so we don't expect to – not the plan to sustain a level of this kind of payout for sure. Is that where you're going on the net debt, sorry, Gerry?

No. That’s great. Well answered. Jean-Paul Lachance: Thanks for your call.

[Operator Instructions] I show no further questions are in the queue. I would like to turn the call back to JP for closing remarks. Jean-Paul Lachance: I did have one other question that came in through some folks, a common theme, which is about the operating costs. Maybe I'll get Todd to just elaborate on our plans to continue to reduce cost here and what he's got planned for that. And maybe you can further elaborate on sort of the facility projects that we have next year, too, because that was another question I got to the mail.

Sure. Yes, obviously, early in the year, we put forth a plan to reduce off cost by 10%, and we were sort of flat in Q3 to the previous quarters. But we did see some higher costs come through in Q3 around government costs like the orphan well levy was a little bit higher than what we had anticipated, maybe a lot higher property tax took a hit at a couple of the counties, Yellowhead and Greenview that we weren't expecting they had indicated that it may be higher, but a little bit more than what we were expecting. And then, of course, typically, you get the AER adding on to that. But production was down with the – with our curtailing production and with the Edson turnaround. So that affected things in the quarter. But in the quarter, we really didn't see given that we shut the sour down sort of mid – early to mid-July, we haven't really yet seen some of the gains from those costs associated with processing and recovering sulfur. So that's starting to show itself in Q4 and will continue. So in that regard, we're – and with the higher production that we're seeing, we're well on the way to achieving that 10%. And then in 2025, we'll continue to work on bringing the cost down. We were $0.45 before the acquisition. That's what we're trying to get to. It's going to take some time and some hard work out there. But we're doing things out there. We're trying to level production fill plants with the drilling program, and I can kind of speak to that on the facility projects. But moving gas in the field so that we can efficiently get gas to plants where they're not currently full. That just helps overall inefficiencies and bringing costs down. As far as capital projects, JP, you mentioned a compressor station in Downtown, Peyto. South Downtown, maybe [indiscernible] down there. But that project will take some legacy gas that's with the development that's happened sort of in the back half of the year here, we've really seen the gathering system pressures come up and there's a lot of plans. We've been working with the development team. They show us where development is going to happen. And so we've got to accommodate that. So we put some pipe in the ground earlier this year. And now we need to reduce those gathering pressures. We'll get that gas down to Oldman. A lot of it – a good chunk of it is Cardium gas. We'll get it back to a lower pressure we've even seen for the past many years and get some better liquid recoveries on that. We've also planned to connect the Edson gas plant to Cascade, and that's going to give us some redundancy so that when Swanson has to turn around in the future, Edson has another turnaround, we've got two sources that can deliver all of the gas. So that's a really good benefit in the future. Then obviously, we're going to continue with several gas gathering system projects to move gas up in Wild River, Cecilia area and just like I say, sort of level load the production with the view that hopefully in a few years, we get to that 160,000 BOE, and we've got to make sure that it can – it's got plants that can – that the gas can get to. So we're looking at that on the long-term and doing things right now to short-term help to gathering system and help production but also accommodate the long-term development. Jean-Paul Lachance: Great. Well, thanks, Todd. Okay. If there are no further questions, thank you for tuning in, and we'll see you next quarter.

This does conclude today's conference call. Thank you for your participation. You may now disconnect.