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. [Operator Instructions] Please be advised that today's conference is being recorded. I'd like to hand the conference over to our first speaker today, JP Lachance, President and CEO. Please go ahead.

Thanks, Marvin. Good 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. Present with me 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 echo, anyway. We still managed to generate $155 million of funds from operations and $51 million of earnings, in large part due to our systematic hedging program, which realized $68 million in gains, along with our industry-leading low cash costs. A reminder that our mechanistic hedging program is designed 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. Ideally, we'd be out of the money in our hedges, but this approach to date has accumulated over $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 is 62%, with these low gas price streams very well as compared to our competitors, and 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 quality program perspective. We were set up on three well pads for the most part through Q2, during what was a typical wet season to a spring breakup. Of course, that minimizes moving equipment around and slogging through the mud. Obviously, that slows down our on-stream timing, but 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 in 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, the Notikewin, and they were drilled over a large portion of the Repsol 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 costs to attain these outcomes are similar to or even slightly cheaper than what we're currently spending on our legacy lands, since we're using the same well designed 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 costs by about $0.05 per Mcfe. Going forward, we expect our royalty rates to be around 7% to 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% to 6%, since we pay royalties based on Alberta reference prices and not our hedge book. Payto continues to have the lowest cash costs in the business and one of the highest margins, 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. 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 own 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 NGL liquid by selling that ethane back in the gas space, but the value we realized was essentially no different. We were saving third-party fees and increasing the plant utilization at the gas plant. And I think this is a good example of the way we look at the business, the way we run the business. It's about making money, not about BOEs. Along 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 pay-to-net production from the sour gas unit that fed that part of the plant, but those wells produce very little NGLs and they have higher shrinkage, and so the cost to operate doesn't make economic sense, 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 land. We have a steady diet of non-accumulating wells for the balance of the year, along with several Dunvegan, Wilrich and some Falher wells that 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 evolving projects and build productive capability for later when we expect prices to be better. We're still planning to spend around $450 million this year at the low end of our guidance, and we're targeting year-end exit around $135,000 BOEs a day, of course assuming prices cooperate and we improve them there as we expect. As mentioned in the release and previous monthly, we have been providing gas to the Cascade Power Plant directly through our pipeline for some time now for testing and commissioning purposes. Our contract is expected to formally kick off here on or before September 1, so soon. In closing, I'd like to remind everyone we remain bullish on natural gas for the near future as demand forecasts continue to rise in North America. Natural gas is a reliable, critical fuel for industrial use, for power generation or just to heat our homes. Significant LNG gas is coming online in North America in the near term, and the potential for datacenter 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. Specific to Payto, we've protected revenues with our low-cost focus and discipline hedging strategy, not only for the balance of ‘24, but we have lots of gas hedging to ‘25 and even ‘26 at prices that are at or above $4 an MCF. As I mentioned earlier, we hope prices will even higher, but 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. New assets are working great. We have room to grow without large infrastructure costs to expand. So despite the current gas price environment, things are looking pretty good. So I imagine there are some questions. We have a few coming in overnight here via email, but I think we'll go to the phones first. Marvin, if there's some questions that folks have queued up for some questions, we'll take those now.

Thank you. At this time, we'll conduct the question-and-answer session. [Operator Instructions] 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? If not, do you see it as being an opportunity here to unlock?

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, especially on the fluvial channel systems in the deep basin, but also for structural reasons to help us understand the structural elements of the play. 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. We actually put -- marry those two together to make decisions on drilling wells and to reduce risk. So, from our perspective, whether it's high-resolution or just typical seismic 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 solution to deciding where a well is going to be drilled, for example.

Thanks, JP. Can I follow up with a slightly different question? 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're aware of 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. We have enough products. One of the things is NGLs. A lot of NGLs move on rail, but we generally go into storage. 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'd be looking at warming up our plants and reducing propane. It's really propane that runs on rail for the most part of the province. So we don't see an impact on a rail strike here at this time.

Perfect. Thank you, JP.

Thank you, one moment for our next question. [Operator Instructions] Our next question comes from Chris Thompson of CIBC. Your line is now open.

Hey, good morning, everyone. Thanks for taking my questions here. Just the first one on managing your capital and building that productive capacity. When we look back at some of your disclosure through the year thus far, it looks like you might have about 9 drilled and uncompleted wells have been added to the inventory. So I just wonder if we can talk through a bit of color on that. And then, sort of, as we get closer to Q4, can you help us quantify how many wells will you have sitting ready to come on production in a better price environment?

Hi, Chris. Thanks for your questions. As far as managing the inventory, we have about 10 ducks right now, to answer your question. And as far as how we manage those, I mentioned that we likely will bring them on at some rate. So I don't see us having a large amount of ducks. It'll be more that we have other tropes and 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 ton. It goes to third parties where we have a higher cost structure. So those are the things. And so it's really more about managing the existing production. The Wilrich production that comes on will likely be choked and or shut in depending, we want to do some testing here while we've got a chance. We'll do that to test the gatherings. Backup is always an issue for us because we've got a lot of legacy production that is habituated to certain pressures in the system. 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, it's hard to point to a number like what is that value, but like I said, we expect to still exit this year at $135,000 by the end of the year. That's despite the fact that we've actually taken roughly 2,000 by plus some gas from the sour unit out of our base decline rate.

Right. Okay. And then just thinking about the shape of that profile, you've previously talked about maintaining relatively flat production through Q3. I'm just wondering if that's still the intention and therefore we sort of knew that volumes were somewhere between 50 and maybe 50 million coming out in line. So, any guidance around 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 ECO/ Empress [ph] market. I always say we don't have ECO exposure. We can sell it at Empress, but the Empress market is not connect -- or is basically selling the same price as ECO, so there's no value in that. So really how we're managing production right now is at a state where we're going to continue to deliver obviously our hedged volumes and then anything above that is going to go to our diversified locations, which is another 150 million. And if you include Cascade in that 160 million, so in total sour there. And so when you add that all up, that's where we get sort of 122 level in 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 obviously come in, but there's a dollar difference at ECO right now, when you look from October to November. So October does turn out to just be a dollar. Then we'll defer the production ramp up to November, whatever it takes, right?

Okay, got it. Yeah. I guess is there, in terms of historically, pay-to-risk was always guided as an exit rate. If pricing remained weak, is there a time where you'd look to updating the market in terms of how you're thinking about those exit volumes?

Yeah, of course. I think our next time we'll be on the call here will be November and I'll be a likely time to do that if things were to fall apart as you're describing.

Okay. And then just a bit of a different question here with respect to cash taxes. It looked like 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 expectation for the whole 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 to 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'd now like to turn it back to JP Lachance for closer remarks.

Yeah, okay. There's a couple of questions that have come in about 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?

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. 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 -- and this is a good example of applying modern wellbore design to some really premium reservoir. And the early time results for these wells are coming in at nearly 2 times the average one-mile result from just several years ago. So really seeing some great results. And the other nice thing here is we've got a lot of inventory in this particular place. So we're really expecting to be able to continue to lean on this and drive some really great results rate in this core area.

Yeah. Thanks, Riley. 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 and maybe even production, a little bit of what you see for us. So the impact, obviously, this is moving the needle towards the 10% reduction by the end of the year. And this is part of that project. It's not included in our Q2. So this is such a three initiative that you guys have. We did it a little early because prices were bad and 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. So maybe you can elaborate a little bit more about this whole sweetening what you'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 Alton [ph] unit and then some from the wells sort of up north in the area we call Burland [ph]. So as far as a reduction in operating costs, we're estimating on a full year, it's probably a 5% reduction. And that would equate to about $0.03 per Mcfe fee 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 be able to take 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 would expect to see in the back half of the year, given that the plant came down, the sour side came down in early July, that we'll start to see some operating cost reduction for sure that will help to get us to that 10% target. It gives us good visibility that we're pretty confident that, obviously, you've got safety costs, carbon tax will manifest next year, 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. Sounds great.

Okay, I'm just going to turn it back to the operator here for another prompt or question.

[Operator Instructions] I'm showing no further questions at this time. I would now like to turn it back to JP Lachance for closing remarks.

Okay, 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 in 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. You may now disconnect.