Hello, and welcome to Peyto Exploration & Development Corp.'s Second Quarter 2025 Financial Results Conference Call. At this time, all participants are on a listen-only mode. After the speaker's 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. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. I will now like to turn the conference over to Jean-Paul H. Lachance, President and CEO. You may begin. Thanks, DeWanda. Morning, folks, and thanks for joining Peyto Exploration & Development Corp.'s second 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 Millar Frame, our Chief Operating Officer; Tavis Carlson, our Chief Financial Officer; Todd Burdick, our Vice President of Production; Mike Collins, our Vice President of Marketing; and Mike Rees, our Vice President of Geoscience. Before we discuss the quarter, on behalf of the management group, those that are here and not here, I'd like to thank the entire Peyto Exploration & Development Corp. team, both in the office and in the field, for their contributions to another strong quarter. Peyto Exploration & Development Corp. remained active with four rigs during the second quarter through spring breakup. As is typical for Peyto Exploration & Development Corp., production falls a little through Q2 as we try not to overspend, fighting through the mud to complete wells and bring them on production. The fires near Fort McMurray did cause some oil sands shut-ins that affected demand for natural gas in the province, and there was some NGTL maintenance that caused prices to go negative at least for one day in June. We did shut in some production that day, not because we had to, but to be more opportunistic and essentially get paid to fulfill our physical contracts and save our gas for another day. This had a marginal effect on production for the quarter, but I bring it up because it's something we'll continue to consider as we move through the summer. Quarter production was just under 132,000 BOE/d, up 8% since the second quarter of 2024, and our cash costs were down 13% over the same period to CAD 1.31 per MCFE as we continue to lead the industry in that regard. Our strong hedge book added CAD 53 million in total gains, which added CAD 0.75 per MCF to our realized gas revenue, and our market diversification contributed CAD 0.53 per MCF net of transportation costs over and above the monthly AECO pricing. All these factors combined to increase funds from operations by 24% year-over-year as we generated CAD 191 million in the quarter, or CAD 0.95 per diluted share, which was also up 20% from Q2 last year. We did not have much gas exposed to AECO pricing in the quarter since we have Empress Service, which can net us better realizations than AECO, particularly when access to storage is restricted, which happened in Q2. In fact, we sold some of our excess Empress Service during the quarter, allowing us to collect incremental income along with third-party processing at Brazeau. That added CAD 0.07 per MCFE to our sales revenue in the form of other income. Our operating costs were slightly higher, a penny higher than the prior quarter. While our controllable operating costs were down quarter over quarter, we received our 2025 property tax bill in Q2, and it was higher than anticipated, so that resulted in an adjustment that's reflected in the higher op costs. Despite this, we remain laser-focused on continuing to reduce the costs we control, and we're forecasting lower operating costs for the rest of the year, and I might get Todd to elaborate on that later in the call. Royalties were a lot lower in the quarter than last year because of weak AECO prices and increased gas cost allowance credits, and we expect royalty rates to be around 5% for the remainder of this year based on the current strip. Interest costs were also lower in the quarter as interest rates have come off and we continue to reduce bank debt. In fact, we paid down CAD 40 million of net debt in the quarter and CAD 105 million year to date. Taken together, our cash costs were down CAD 0.11 per MCFE quarter over quarter and CAD 0.19 relative to the second quarter of 2024. All in all, we have the lowest cash cost in town, but more importantly, I think one of the highest margins. As, of course, you know, our low-cost structure and our strong hedging and diversification strategy allow the company to weather volatility in the commodity markets. Switching to operations, we drilled 19 wells in the quarter, completed 19, and tied in 21. Part of the drilling program included follow-ups to the Q1 Cardium wells that were drilled in Brazeau, where we used a different drilling and completion design. We talked about that then. The first two wells we drilled were low working interest, which helped us to test the concept. The next three wells that we followed up with in this past quarter were at 100% to see and make sure we could repeat the results. At the end of the day, the key takeaway here is that we reduced our drilling and completion cost per meter by about 37%, and that should really help us as we look to improve the economics of future Cardium locations across our large inventory. Willrich continues to perform well, as I detailed in the recent monthly letter, having dialed in our most recent design and applying it to the high-quality land we acquired from Repsol. We also completed another well in the prolific flare channel trend in the quarter that we discovered last year in the Greater Sundance area. That well has already produced over a BCF of gas, and it's the best outcome on this trend so far. We have since drilled a follow-up well that we'll be completing shortly, which will help us to delineate the trend and give the team more confidence in the 20+ locations that we see in the play. We started construction of a 30 million a day field compressor station in the Greater Sundance area. It will move more liquids-rich gas to the Itsen Gas Plant via the Central Foothills Gas Gathering System later in Q3 and into Q4. I might get Todd to elaborate on the details of that project later. That's going to help clear out some existing gathering system for a large-scale development that we have planned in the area that will take gas to Swansea and Old Mammoth. The long-waited LNG Canada facility exported its first cargo right at the end of the quarter. I think it was June 30. We expect this will be constructively amazing in the long term, but you know we should be patient as things ramp up here. In the meantime, we have plenty of production hedge for the summer, about 500 MMcfpd, priced at CAD 4 an MCF, and the rest of it's diversified to hubs in Eastern Canada, Chicago, and Midwest where prices are stronger. Our business plan and guidance for 2025 remains unchanged. We plan to spend between CAD 450 million - CAD 500 million to generate production adds at a capital efficiency rate of about CAD 10,000 - CAD 11,000 per BOE per day by the end of the year. That should more than offset our annual corporate decline, which we estimate is about 27%. We have a large number of potent non-QN locations and more of that new flare channel wells planned for the rest of the year. We expect these locations will bring our annual average productivity back to something similar to last year's stellar performance. We also have some Bluesky and Viking wells planned that will follow up on past successes as well. We're not slowing activity per se because we want to keep our crews steady and we want to, you know, as we expect to ramp up production in Q4, which will coincide with better winter pricing and as LNG progresses to full capacity. Of course, we'll remain flexible with our plans as we always are. At the end of the day, we sell a product that the world needs, and we run our business in a way that is sustainable. We keep our costs as low as possible. We diversify our sales points. We hedge the near term so that we can constantly fund our capital program and reward our shareholders with profits. It's simple, predictable, and maybe perhaps a little boring, but we make no apologies for that. Okay, I imagine there's some questions. Tawanda, perhaps we can go to the phones first. Thank you. Ladies and gentlemen, as a reminder to ask a question, please press star one one on your telephone, then 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 Christopher Thompson with CIBC Capital Markets. Your line is open. Hey, good morning, everyone. Thanks for taking my questions. Morning. Just to start out, you talked about some of the recent successes at Chambers in the new well core design. Just wondering, how does that compare to other competitors in the area? Is Peyto sort of at the leading edge of this approach, or is this something that you've seen other operators do and then now you're adopting? Yeah, as far as the, I mean, obviously, you know, we mentioned that last quarter that this isn't something new in the industry. It's something that others are already doing, at least in the oil part of the play. The concept of going, you know, drilling a little bit lower into the biodegraded zone just helps us with penetration rates. We talked about this last quarter. I wouldn't, you know, we, I don't know if there's a lot of gas guys doing this per se. I'm looking at Mike and Riley here, and they're nodding their heads, no. We might be, you know, there may be a couple other companies doing it. I don't know that we lead, we lead, but it's certainly an improvement for us, and it's important for our long-term, you know, Cardium inventory to get those costs down, right? Okay. I guess just sticking to that Chambers and Brazeau area, can you maybe expand a bit on the third-party gas that you're bringing in there? I think you mentioned CAD 0.07 an MCFE. Was that specific to Brazeau? That's a combination of us selling some excess Empress Service and the Brazeau processing fee income that we would have received. It's not just Brazeau. Maybe I can get Todd to elaborate on some of the other sort of sources of our fee income, our third-party fee income. Todd, do you want to comment on that a little bit more? It's not just that area, though, just to be clear, Chris. Yeah, for sure. Definitely, some opportunity, some further opportunity in the Brazeau area. I think we mentioned last quarter when we commissioned that pipeline that we built it so that we can add, and we've been, our CEO has been busy talking to others in the area. You know, up in Greater Sundance, we've had some producers that have been sending third-party gas to our Swanson plant for quite some time. We've been talking to others up there. The TV group's pretty active. We've got a little bit up in Kakwa. You know, it's kind of spread out all the way from Kakwa down to Brazeau. It's definitely not just happening in Brazeau. We're always working with other producers who may be looking to shut down plants or other things, and it helps them on their OpEx and helps us on the other income part of the balance sheet. Right. Got it. And then just this next one for JP. How are you thinking about capital allocation as we think out 2026 and beyond between organic growth and M&A, and then, you know, as you approach your debt targets, potential shareholder return increases? We still believe that, you know, we're going to put money into the drill bit to grow modestly over the next two years. We don't have, we haven't come out with a formal plan for 2026 yet. Certainly, that's probably going to look a lot similar to the last two years from what I can, you know, from what we can predict at this point in time. We'll see where prices and everything go from here. We, you know, will continue to make debt repayment a priority. We have a soft debt to EBITDA target of one times, trailing 12-month EBITDA of one times. That hasn't changed. When we get there, which we expect will be sometime in 2026, we'll relook at that capital allocation strategy. That depends on where prices are at. LNG Canada came on and things, you know, AECO and price, you know, the differential or the basis between that proves all those things happen. We'll start looking at our diversification and all those things. We'll look at how we see the market and how the business is, and we'll decide then how we change that allocation, if we change that allocation to where it is right now. We've got a fairly comfortable dividend level right now that we feel is very sustainable, and we're going to continue to grow. Nothing really has changed from what we've been messaging all the way along, Chris. Got it. Just last question from me, JP. You touched on AECO improving. How are you thinking about the marketing strategy here? Looks like your 2027 book has pretty sizable exposure to domestic benchmarks and, you know, relatively light on the fixed, which we expect will increase over time. How are you thinking about that? Which hubs do you see as having attractive pricing on the strip that you'd be looking at? We still believe that diversification is important. Diversification doesn't mean not AECO, but AECO is part of that. In fact, our exposure to AECO is in the fact that we would like to hedge some of that in the future, right? As we move closer to 2027, we'll build that up. Nothing's changed in our hedging strategy plan, right? When we get to 2027, any season there in 2027, we're going to be minimum to 50% hedged because we know this volatility in commodities is real. As we move forward, we're going to continue to bring up the hedge book in 2027. When we do that, right now prices in 2027 and AECO are pretty good. As we take some of that off the table and we see maybe the effects of LNG Canada narrow that basis, which improves that even more, then we'll take some more of that off the table. We'll have similar exposure going forward as we have today. Some AECO, a little bit AECO, a little bit of everything else too. We think that's important not to have just one market. We're not, we think it's good. We want it to improve, but we're not counting on it as it were. It doesn't sound to me like having additional exposure to AECO compared to where you've historically been in the last couple of years is something that you'd be really looking for? Yeah, we're only looking, remember, we only hedge two and three years out. To the extent that AECO improves, we have a whole lot of reserves that would be exposed to that in the future should AECO really start to run and become, say, a premium market or something different than what it is today, right? This is about managing things in the short term. I don't think, I don't see us changing our strategy in that regard. Okay, that's all for me. I'll hand it back. Thank you. Okay. Thanks, Chris. Thank you. As a reminder, ladies and gentlemen, let's star one one to ask the question. Tawanda? Yes. I have some questions here from Lynnette coming in overnight. If it's okay, I'll ask a couple of those here of the team. All right, I'll hand it back to you. Todd, we did talk earlier about, you know, the OBED compressor that we're going to install. You've already started construction on it here. Some questions around, okay, what's, you know, what is, can you elaborate a little bit more? Where is this and how is it going to help us? Sure. The compressor is, I guess, best described as the heart of the original Peyto Sundance area, geographically, Township 53-21, W5P, for those who are familiar with the area. There are a lot of vertical penetrations in the area, a lot of horizontal and Cardium, not a key man's flares, Wilrich, a lot of depletion. With the Repsol acquisition, obviously, as JP mentioned, there is a development plan in the area. When we looked at it, we said there is a lot of production here that needs to be protected from higher line pressures when you are bringing on these bigger wells. After doing some sensitivities, it made a lot of sense to take and build a compressor, collect that older gas, which is a lot of Cardiums, flares, and not a key man's, as I mentioned, that is the bulk of it. With the pipeline infrastructure that we bought, along with the Repsol asset acquisition, it allowed us to tie that gas in with some modest pipeline expenditures down to the Edson gas plant where we can get a lot better liquid recovery from, especially the Cardiums versus Oldman or Oldman North. Oldman obviously had the deep cut, but Edson had much better recoveries, and some of this gas went to Swanson. We are going to collect about 30 MMcfpd -3 5 MMcfpd initially. We built the plant so that we can expand it to that 60 MMcfpd - 70 MMcfpd just with another DI and some more compressors. We are expecting to see somewhere around a 10 barrel per million uplift on the gas moving either from Swanson, Oldman, Oldman North down to Edson. It could be better. It will depend on the species. Along with that, as I mentioned, you take, and I think JP alluded to the press release, you take 30 million or 35 million a day out of the gathering system that is going to Edson or to Oldman and Swanson. You are going to free up room. You are going to see some flush until we backfill that production with new production. As well, all that 30 million a day gas that you are sending to Edson is now going to be at a much lower line pressure, probably half. That helps the economics of those wells long term. There are a lot of little parts that come into play into the advantage of building this compressor station. Things are going really well. We are probably a month out, maybe a little bit longer until commissioning, where the guys have been, despite the rain, we have been shut down a little bit and had some delays, but things are moving along really, really well. Okay, good. Thanks. Yes, Todd. Another question was about the well outcome so far this year. Maybe I'll get Riley to address that. We expect some improvements on the back half of the year. Can you talk about the kind of species we are going to be drilling? Can you elaborate a little more? Can you give us a little more color on that? Yeah, you bet. When we're looking at the performance for the first half of the year here, we're actually very happy with where we're tracking relative to where we were last year. If you guys recall, in 2024, we had a much more Wilrich-centric program in the first half of the year and a much more Notikewin and Falher-centric program in the second half of the year. Very similar to 2024, I think what we'll see is that curve improves as we move forward through the second half of the year. When we distill it down to what's really important here, looking at what we're spending for what we're getting, I think we're right on track with 2024. I would expect us to be in line with those outcomes as we do the second half of the year. Okay. We talked about in the press release, and I mentioned it here earlier, we're following up with some past successes, not a couple of plays that we haven't done recently. One of the questions was the Viking, the Bluesky. It's not something that people, I guess, you know, the investors hear a lot about. Maybe I get Mike to elaborate a little bit on what we're pursuing there in the Viking, the Bluesky here this year, later, later part of this year. You bet, JP. It has been a little while since we dipped our toe into the Viking. We drilled our first Viking well about two years ago. That was a fairly successful first test for us on our lands. We're looking to wrap up actually the second well and do all that in the Viking right now. We see a material amount of upside on our land base in the Viking and also on the Bluesky. We haven't actually drilled a Bluesky for a while. I think that goes back about five years, to 2020. We did inherit, as part of the Repsol acquisition, a Bluesky well that Repsol had drilled that I believe we completed. That turned out to be quite a good well. Again, material upside in the Bluesky on our existing land position. We are drilling the first Bluesky well currently, and we have a couple more planned for the remainder of the year. If the results come in as expected in these two zones, we will be more aggressive with them in the future. Thanks, Mike. I don't know if there's any more questions from the phone lines. As a reminder, ladies and gentlemen, let's star one-one to ask the question. I'm showing no further questions in the queue. Okay. Thanks for tuning in, folks. We'll see you on the next call in November. Ladies and gentlemen, that concludes today's conference call. Thank you for your participation. You may now disconnect. Everyone, have a wonderful day.