Good day, and thank you for standing by. Welcome to the 2024 second quarter Peyto's Financial Results conference call. At this time, all participants are in listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you'll need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I'd like to hand the conference over to your first speaker today, JP Lachance, President and CEO. Please go ahead. Thanks, Marvin. Morning, folks, and thanks for joining Peyto's second quarter conference call. 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. Presently, present with me and to answer your questions in the room here 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. Firstly, we'd like to thank the entire Peyto team, both in the office and in the field, for their strong execution this past quarter. It was a strong quarter for Peyto, despite very low gas prices. In fact, the lowest we've seen since 2019 at AECO anyway. We still managed to generate CAD 155 million of funds from operations and CAD 51 million of earnings, in large part due to our systematic hedging program, which realized CAD 68 million in gains, along with our industry-leading low cash costs. A reminder that our mechanistic hedging program is designed to de-risk, to de-risk and smooth out prices and give us predictable revenues so we can provide confidence to run our capital program, manage the balance sheet, and pay shareholders a dividend. You know, ideally, we'd be out of the money on our hedges, but, you know, this approach to date has accumulated over CAD 350 million in hedge gains since we started. The other point I would like to point out about the quarter is that I think Peyto's operating margin of 62% with these low gas price screens very well as compared to our competitors, and it's, it's a testament to how we run the business. Let's talk a bit about the drilling program. We completed another string of very long laterals in the second quarter, mostly Wilrich, across different areas in Greater Sundance and in our core Brazeau area. The average lateral lengths of these wells drilled in the program were just over 2,300 meters, which I think is another record for the size of the program from a quarterly program perspective. We were set up on three well pads for the most part through Q2, during what was a typical wet season through spring breakup. And of course, that minimizes moving equipment around and slogging through the mud. Obviously, that slows down our on-stream timing, but, you know, it certainly helps to keep and even drive costs down as we saw overall improvements in our average cost per meter on both drilling and completions operations this past quarter. We continue to be excited about the drilling results from the newly acquired Repsol lands. We had 21 wells on stream to the end of Q2, with enough history that shows a sustained 30% increase of average well productivity as compared to the performance of recent legacy programs. These wells were drilled in the Wilrich, the Falher, and the Notikewin, and they were drilled over a large portion of the Repsol land base. That's important because it provides us confidence that it isn't just one species that's outperforming, but the good results are coming over a wider area and up and down the strata. The other thing that's important here is that the cost to attain these outcomes, you know, are similar to or even slightly cheaper than what we're currently spending on our legacy lands, you know, since we're using the same well design to drill and complete them. Cash costs for the quarter were $1.50 per Mcfe or $1.24 per Mcfe, excluding royalties. We had an annual GCA adjustment to our royalties on the Repsol assets this past quarter that inflated our cost by about $0.05 per Mcfe. Going forward, we expect our royalty rates to be around 7%-8% on a pre-hedged sales revenue basis, or if you include the revenue from our hedge gains, our royalty rate is more like 5%-6%, since, of course, we pay royalties based on Alberta reference prices and not our hedge book. Peyto continues to have the lowest cash costs in the business and one of the highest margins. You know, but despite the fact that we have the lowest cash costs, we still endeavor to improve. We set a goal last quarter to reduce our operating expenses by 10% per Mcfe by the end of this year, and we're pleased that we are basically on target with that goal, having reduced 5% in the second quarter already. Part of that gain was the redirection of gas volumes from a third-party deep cut facility, where we used to extract low-value ethane as a liquid, and we moved that over to our owned and operated Edson Gas Plant through the Central Foothills Gas Gathering System. It meant we had to give up about 2,000 barrels a day of BOE a day of NGL liquid by, you know, by selling that ethane back in the gas phase, but the value we realized was essentially no different, and we basically we were saving third-party fees and increasing the plant utilization at the Edson Gas Plant. And I think this is a good example of the way we, you know, we look at the business, the way we run the business. It's about making money, not about BOEs. Well, in the same vein, we recently shut down the sour gas sweetening side of the Edson Gas Plant. Although we had some third-party income coming in from that, it wasn't enough to offset the cost to run and maintain that part of the plant. Not to mention, running it impacted plant reliability, higher emissions and slightly higher safety risks to operate sour gas, of course. We had to shut in a small amount of our Peyto net production from the sour gas unit that fed that part of the plant. But, you know, those wells produce very little NGLs, and they have higher shrink, have higher shrinkage, and so the cost to operate to make it, you know, doesn't make economic sense, you know, especially at today's gas prices. Currently, we have four rigs running across our core areas, three in Sundance and one in Brazeau. Two of those Sundance rigs are on the former Repsol, former Repsol land. We have a steady diet of Notikewin wells for the balance of the year, along with several Dunvegan, Wilrich, and some Falher wells are all left on the docket here for the rest of the year. We plan to drill and complete these wells, and we may or may not bring them on production, or if we do, it'll be at restricted rates, depending on where gas prices are. But at the very least, we'll use this time to evaluate the gathering system impacts to determine developing projects and build productive capability for later, when we expect prices to be better. We're still planning to spend around CAD 450 million this year at the low end of our guidance, and we're targeting a year-end exit around 135,000 BOEs a day. Of course, assuming prices cooperate and, and they improve from there, as we expect. As mentioned in the release, in previous monthly, we have been providing gas to the Cascade Power Plant directly through our pipeline for some time now for, for testing and commissioning purposes. Our contract is expected to formally kick off here on or before September first, so soon. In closing, I'd like to, you know, remind everyone, we remain bullish on natural gas for the near future as demand forecasts, you know, continue to rise in North America, and natural gas is a reliable, critical fuel for industrial use, for power generation or just to heat our homes. Significant LNG egress is coming online in North America in the near term, you know, and the potential for data center expansion to meet the needs of AI is also being contemplated in many places that should be constructive for both gas prices and, of course, our power deal. You know, specific to Peyto, we've been, you know, we've protected revenues with our low-cost focus and disciplined hedging strategy, not only for the balance of 2024, but we have lots of gas hedged into 2025 and even 2026 at prices that are at or above CAD 4/MCF. And as I mentioned earlier, we hope prices go even higher, but it's, it's kind of nice to know we have that cushion in our business, so we can grow modestly while we return a healthy dividend to our shareholders. Our new assets are working great. We have room to grow without large infrastructure costs to expand. So despite the current gas price environment, things look, you know, looking pretty good. So I imagine there's some questions. We have a few come in overnight here, via email, but I think we'll go to the phones first. Marvin, if there's some questions, folks have queued up for some questions, we'll take those now. Thank you. At this time, we'll conduct a question-and-answer session. As a reminder, to ask a question, you'll need to press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Aaron Bilkoski of TD Cowen. Your line is now open. Thanks. Good morning. So my first question is, one of your Deep Basin producers has been seeing capital efficiency benefits as a result of using higher resolution seismic data. I guess my question is, is this something that you've been doing as well? And if not, do you see there being an opportunity here to unlock? Sorry. Hi, Aaron. It's higher resolution seismic data, is that what your question was? Yeah. We've always used seismic data to help guide us not only on, you know, especially on the fluvial channel systems in a deep basin, but also on for structural reasons to help us understand the structural elements of the play. I'm not sure that, you know. I'm not sure about the high-resolution part of that equation. We've always used seismic as a tool. It's not the only tool we use. Of course, we've got lots of well control as well. So we actually put marry those two together to make decisions on drilling wells and to reduce risk. So from our perspective, you know, whether it's high resolution or just typical seismic, you know, data that we use, 3D, always, generally, is something that we continue to employ and will sort of aid us, but it's not the be all, end all to the, you know, to the solution to, you know, making deciding where a well is going to be drilled, for example. Thanks, JP. Can I follow up with a slightly different question? Yeah. It seems like there is a looming rail strike that could start in the next week or so. If rail service was out for, say, a week or two, do you see that having an impact on your business in terms of frac sand availability or the ability to move liquids? Just any color you could provide would be interesting. No, I don't think we see, we're aware of the strike, the pending or the potential for a strike. We don't see an impact on our business. I don't think it would last very long. A lot of other industries will be affected, ones that might get a little more attention from our federal government than ours to resolve the issue, certainly. But no, you know, we have enough products. One of the things is NGLs. A lot of NGLs move on rail, but we, you know, we put those into storage, and so there's time there to store these things. We also have storage on site for our NGLs should there be a challenge in there. If it really lasts a long time, then we would be looking at, you know, warming up our plants and, you know, reducing propane. It's really propane that runs on rail for the most part out of the province. So, we don't see an impact on a rail strike here at this time. Perfect. Thanks, JP. Thank you. One moment for our next question. Again, as a reminder, to ask a question, you'll need to press star one one on your telephone. Our next question comes from the line of Chris Thompson of CIBC. Your line is now open. Hey, good morning, everyone. Thanks for taking my questions here. Just the first one on, you know, managing your capital program and, building that productive capacity. I mean, when we look back at some of your disclosure through the year thus far, it looks like you might have about nine drilled and uncompleted wells that have been added to the inventory. So just wondering if we can talk through a bit of color on that, and then sort of as we get into closer to Q4, can you help us quantify, like, how many wells will you have sitting ready to come on production in a better price environment? Yeah. Hi, Chris. Thanks for your questions. As far as managing, you know, the inventory, we have about 10 DUCs right now to answer your question. And as far as how we manage those, like I mentioned, we likely will bring them on, at least at some rate. So I don't see us having a large amount of DUCs. It'll be more that we have, we have either choked some wells back or we've shut in some other production that's probably less economic. In fact, I think we have some production right now that goes to a third party, about 500 BOEs a day total. It goes to third parties, where we have, you know, higher cost structure. So, you know, those are the things... And so it's really more about managing the existing production. The new wedge of production that comes on will likely be choked and/or shut in, depending. We want to do some testing here while we got the chance, right? And so we'll do that to test the gathering system. You know, backout is always an issue for us because we've got a lot of legacy production that is habituated to certain pressures in the system. So we're always sensitive to seeing how wells respond to that, and this is giving us an opportunity to do that. So wells will come on and come off, and so this productive capability we're going to build, you know, it's hard to give. It's hard to point to a number, like, what is that value? But, you know, like I said, we expect to—we will still exit this year at 135, and that's despite the fact... Sorry, 135,000 by the end of the year. That's despite the fact that we've actually taken out, you know, roughly 2,000 barrels plus some gas from the sour unit out of our base decline, right? Right. Okay. Yeah, and then I guess just thinking about the shape of that profile, you've previously talked about maintaining, you know, relatively flat production through Q3. Just wondering if that's still the intention and therefore we sort of need to add that volumes are of somewhere between 50 and maybe even 1 million amount online. So any guidance around or on that would be helpful. Yeah. So we said we were keeping production flat, and we're keeping production flat to basically minimize any exposure to the AECO/Empress market. I always say we don't have AECO exposure, and we don't. We have. It's mostly, you know, we can sell it on Empress, but the Empress market is really not, has not disconnected, or is basically selling the same price as AECO, so we're not. There's no value in that. So really, what, how we're managing production right now is at a state where we're gonna continue to deliver obviously our hedged volumes, and then anything above that is gonna go to our diversified locations, which is another 150 million, and if you include Cascade in that, 160 million, so in total, sorry, there. And so when you add that all up, you know, that's where we get to sort of 1.22 level with our current mix of gas and liquids. So we'll maintain that, roughly that level, until we see prices improve. And that right now, if you look at the strip, there's quite a difference between October and November. We expect those prices will, you know, will, will obviously come in, but there's, there's a CAD 1 difference at AECO right now when you look from October to November. So October does, you know, turn out to just be a CAD 1, we, you know, then we'll defer the, the, the production ramp up to November. It whatever it takes, right? Okay. Got it. Yeah. I guess, is there, you know, in terms of... Historically, Peyto has always guided an exit rate. If pricing remained weak, I mean, is there a time where you'd look to updating the market in terms of how you're thinking about, how you're thinking about those, those exit volumes? Yeah, of course. I think we, our next time will be on the call here in November, and that'll be a likely time to do that if things were to fall apart as we're so what you're describing. Okay. Okay, and then, just a bit of a different question here. With respect to cash taxes, it looked like sort of your cash tax rate for Q2 versus pre-tax cash flow was quite light versus Q1. Just wondering how you're thinking about that average tax rate through the rest of the year. Hey, Chris, it's Tavis Carlson here. So we manage the current tax provision based on a year-to-date standpoint. So with the soft prices that we've seen in Q2 and the outlook for Q3, we've lowered our kind of taxable expectations for the full year. So if you look at year to date, we're about 10% on before tax cash flow. So that's probably the best kind of range to go at, looking forward for the rest of the year now. Okay. That's helpful. Thanks, Tavis, JP, and I'll hand it back. Thank you. I'm showing no further questions at this time. I'll now like to turn it back to JP Lachance for closing remarks. Yeah. Okay. Just a couple of questions that have come in about, just about a little more, looking for a little more color on that Wilrich program that we mentioned in the press release that we drilled recently through the quarter. So maybe I'll get Riley to elaborate on the Wilrich results we drilled, particularly on the Repsol lands in the quarter. Riley, do you want to? Sure, yeah. So I think some of the results we've been getting from the Repsol lands and the Wilrich are worth highlighting a bit. ... particularly the Sundance Wilrich program really stands out. You know, so over the years, we've developed the Wilrich and Sundance pretty extensively, but with these new lands, we're actually seeing some of the best results that we've actually ever achieved. We've talked about in the past how we're able to apply all the stuff that we've learned over the years, horizontal drilling, to these new lands. And what we're seeing is this is a good example of applying modern well bore design to some really premium reservoir, and the early time results for these wells are coming in at nearly two times the average one-mile result from just several years ago. So really seeing some great results. The other nice thing here, too, is we've got a lot of inventory in this particular place, so, you know, we're really expecting to be able to continue to lean on this and drive some really great results for it in Hanlan's core area, so. Okay, thanks, Riley. Yeah, good color. And I have one other question here about the sweetening project. Maybe, Todd, you could elaborate a little bit more on what are the impacts of this, maybe from the perspective of operating costs, maybe even production a little bit, what you see for last quarter? From an impact, obviously, this is moving the needle toward the 10% reduction, you know, by the end of the year, and this is part of that project. It's not included in our Q2, so this is a Q3 initiative that you guys have. We did it a little early because prices were bad, and we had some—you know, it didn't make sense to continue to operate that facility, so we did accelerate it. It's maybe saving us a little bit on the turnaround. Maybe you can elaborate a bit more about this whole sweetening, what we've done. Yeah, sure. So, as far as the production impact, it was just under 1,500 BOE that was shut in. Majority of that coming from the Elkton unit, and then some from some wells sort of up north in the area we call Berland. So as far as a reduction in operating costs, we're estimating on a full year, it's probably 5% reduction. And that would equate to about CAD 0.03 per Mcfe, say, we're modeling for 2025. So some of that will manifest in Q3 and Q4. Obviously, there's some capital costs and operating costs to shut down the amine plant, the amine process, the sulfur process, that sort of thing. There's work to be done on the CFGGS as that gets sweetened. We'll have to—we'll be able to take some some ESDs offline. That actually caused us quite a bit of grief last winter, when it got cold, so it'll be nice to have some reliability on that. So yes, we, we would expect to see kind of in the back half of the year, given that, you know, the plant came down, the sour side came down in, sort of early July, that, that we'll start to see some, some operating cost reduction for sure, that, that will, you know, help to, to get us to that 10% target. It, it gives us good visibility that we'll—we're, we're pretty confident that, you know, obviously, you've got safety costs. Carbon tax will manifest next year, but... and high maintenance costs on some of that stuff that's not running anymore. So pretty confident that we'll see that'll be a good part of the reduction. Yeah, sounds great. Okay, I'm just gonna turn it back to the operator here for another round of questions. Again, as a reminder, to ask a question, you need to press star one one on your telephone. I'm showing no further questions at this time. I'd now like to turn it back to JP Lachance for closing remarks. Okay, thanks. Thanks, everyone, for tuning in. I realize it's vacation time, so some of you folks may not be even in the office these days, but I appreciate it, or you're off to the cottage somewhere. So thanks for tuning in live, and we'll talk to you again next quarter. Thank you for your participation in today's conference. This does conclude the program. 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