Thanks, Michelle. Morning, folks, and thanks for joining Peyto's second quarter 2026 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 that was issued yesterday. Here in the room with me, I have most of the management team, including Riley Frame, our Chief Operating Officer; Tavis Carlson, our CFO; Todd Burdick, our VP of Production; Derick Zember, our VP of Land and Business Development; Mike Collins, our VP of Marketing; Crissy Rayfluss, our VP of Finance; and Mike Rees, our VP of Geoscience.

Before we discuss the quarter, on behalf of the management group here and as always, I'd like to thank the entire Peyto team in the office and in the field for their contributions to another strong quarter. It was a wet spring and early summer in the areas that we operate, we had a lot less activity in the field, especially when you compare that to Q1.

Yet we managed to maintain production levels more or less at the same level thanks to a strong drilling program in Q1. We paid down some more debt, we increased the dividend in May, we drilled more great wells, we added more undeveloped acreage, signed another important natural gas diversification deal as well.

I think that's pretty good for a typically quiet quarter. Let's dive into some details with operations first.

We slowed drilling activity down as we typically do during the spring breakup. We only spud 10 wells, which is reflected in our capital spend of only $68 million in the well-related costs, and includes some completions that would have spilled over from Q1.

The average performance of these wells are tracking closely with the last two years' outcomes, and we're particularly pleased with the latest Cardium drills down in Brazeau. We applied the same drilling and completion strategy that worked so well last year in the area just south of there in Chambers.

This is where we drill a little deeper in what we call the bioturbated zone to increase the drilling speed, and then we complete the longer horizontal with more stages to increase stimulation intensity. The gas rates are better, but most importantly so are the wellhead liquids.

We have initial liquid rates of 400 to 600 barrels per day. Now we're applying our Cardium learnings up in the Sundance area to see if we can repeat those results and improve the internal rates of return up there as well.

Peyto also invested $14 million in facility projects that include major pipelines, plant optimizations, and some maintenance work during the quarter. We completed some plant turnarounds with minimal effect on production since when we planned these, we tried to redirect volumes to other plants and staged the shutdowns to maximize online time.

Maybe I'll get Todd to expound on that later. The credit of these efficient turnarounds goes in part to the great execution by our team in the field, but also to the planning that goes into these things in the office.

This is an element of our own-and-control strategy that I think is often overlooked. We're not dependent on third parties' performance for these kinds of turnarounds.

The majority of our gas, 98% of our gas is controlled by us and goes to our plants. The balance of our capital was spent in Q2 the balance of our capital that was spent in Q2 was $2 million is used to capture another 26 sections of land through Crown sales and direct purchases.

That brings new land purchases so far this year up to a total of 53.8 net sections at an average cost of $158 per net acre, which cheaply adds to our unbooked drilling inventory. At the start of Q2, we redirected about 85 million cubic feet a day of sales gas to a third-party deep cut facility to increase our C3+ or propane/butane recoveries mostly and some condensate, which adds an incremental 1,500 barrels per day, and that's helping to bring our corporate liquid content up from 12% to 13%.

The other part of that is the Cardium program, of course, that's adding some more liquids. Switching to financials, controllable cash costs in the quarter, that's operating, transport, interest, and G&A, totaled $1.04 per Mcfe, which brings us down to the pre-Repsol levels before Q4 2023.

That speaks to the great effort by the Peyto team to stay focused and integrate these assets into our low-cost model. Flipping to revenue, another strong quarter, where our realized gas price was $3.42 an Mcf, which is double the average AECO monthly for the quarter, which was a buck 64 when it's adjusted for per Mcf when you adjust that for our heat content.

Once again, the diversification value of 93 cents per Mcf played an important role, and the rest of the gain we saw was from 85 cents of hedges. Speaking of diversification, we added another piece to our portfolio in Q2 with the Centrica gas supply agreement that fetches us TTF, European TTF-based pricing, less deductions.

That starts sometime in 2029 and delivers 50,000 MMBtu at NIT or at AECO at a very attractive netback. Of course, that agreement is confidential, but it does bring our total unhedged diversified volume, so that's non-AECO price-related volumes, to 400 million cubic feet a day in 2028 and beyond.

Combine the low cost and the great pricing that we got, at least relative to AECO, it meant we generated $228 million in funds from operations, that's $1.11 per share, and adjusted earnings of $150 million, or 50 cents a share, and we have continued to impress with an operating margin of 71%. We announced a monthly dividend increase of $0.01 per share, that's up 9% in May, and that was paid out starting in June, and we still paid down total net debt by $72 million.

There's no rest for the wicked, and we're back up to running four rigs. We expect to hold that there for the rest of the year.

We've continued to modify our drilling program going forward to shift even more towards some of the liquid-rich species like the Cardium and the Flare. You can refer to the latest corporate presentation for reference to that.

I think it's on slide 21. Gives you a breakdown of the species that we're going to drill this year in the fall of this year.

We remain well-protected for the rest of the year with just over 500 million cubic feet a day of gas hedged over $4 an Mcf and about 400 million cubic feet a day secured for 2027, at least so far, at $3.30 an Mcf, both of which are higher than current strip, which isn't bad. The rest of our production is pointed to downstream markets and with really no summer exposure to spot AECO prices through 2027.

When combined with our liquid hedges, that secures $485 million for the rest of '26 and another $590 million for 2027. This, along with our industry-leading cash costs, our market diversification, and the great well results we're seeing, gives us the confidence to remain committed to our guidance, which is investing $450 to $500 million and drilling 70 to 80 net wells for 2026.

We remain constructive for natural gas with the continued tailwinds that are presented from LNG Canada and LNG build-out in Canada and the U.S. and the increased demand from local markets like power for data centers.

Peyto's strategy remains the same: we focus on execution, control things that we can control, that's costs, while mitigating the risks on the commodities. How we do it.

We believe this is a winning recipe, and it provides long-term returns to our shareholders in a very volatile commodity market. I imagine there's some questions, Michelle, maybe I'll turn it over first to the phones.

I've got some other questions that came in overnight, but maybe, Michelle, we'll start with anybody on the phone that wants to ask a question. Go ahead.

Maybe I'll give some time for people to think, and I had one question that came in about a little more information about what we're doing with this Cardium play and how we might be applying that up in Sundance. Maybe I'll ask Riley to maybe expound upon that a little bit with respect to how we're doing and what we're doing in Cardium these days.

Sure. Yeah.

Like we talked about mostly over the last little while here, we've been active in the Brazeau area. We're going longer sort of amortize the fixed costs of our wells.

Drilling in the bioturbated zone to increase our ROPs. Then, obviously, we're increasing our stimulation intensity to try to improve on our per-meter performance.

Like we talked about in the press release, that's translated into a 37% improvement in our drilling cost per meter horizontal, which is a huge improvement. We still think there's room to work on the completion side of that.

One of the things that we did here just recently with the last pad we drilled was we tried a coil shiftable sleeve system. There's some significant advantages to that system as we start talking about cemented liner systems.

We just finished up those completions here recently, it's still early, but everything's looking pretty positive that we've actually been able to move costs in the right direction there. We're on track to see an even larger cost reduction on a per-meter basis as we go forward.

Translating that over to the Sundance area, we recently drilled our first pad in Sundance since 2022. Really trying to take what we've learned from Braz and apply that as best we can.

It's not necessarily be translatable. There's a few differences.

The main goal here was to try and drive horizontal lengths longer. This first pad, we were able to increase horizontal length by about 50%, which is pretty meaningful.

The big difference up in Sundance would be that we don't really have the bioturbated zone to chase, going low and improving that ROP in that bioturbated zone isn't really an option. That length increase is still meaningful as it pertains to decreasing the per-unit cost as we're drilling these wells.

Then the other part of it would be increasing the stimulation intensity and driving that tonnage per meter number up a bit to try and get higher per-meter rate. Overall, the first couple wells we drilled here, looks like we've been able to reduce our horizontal per-meter cost by about 10% on the drill side, which is a good starting point.

I think we'll continue to try and move that further down. Those wells were completed just sort of began late last week here, it's still early time.

Overall, it's very encouraging, and I think it will really help us to drive proved economics in Sundance Cardium play across the board where we have obviously a lot of reserves booked, as well as a lot of locations. Stay tuned on that as far as where we go with that one.

That sounds good. Essentially we're trying to pull on both levers, both the cost side, right?

The production side, cuz of course, what matters most is returns, not just increasing production in these wells

and

having the costs matter as you point out. That's good.

Exactly. Another question that came in was this new term we've introduced in our press release or in our MD&A as well called adjusted earnings.

Just wanted maybe Tavis to give you a chance to sort of explain that maybe in layman's terms a little bit more about what do we mean by this adjusted earnings? Thanks.

Thanks, J.P. It mainly stems from our new Centrica gas supply agreement.

The TTF component of this contract is viewed as an embedded derivative, and we have to separate that from the underlying AECO component of the contract, account for it as a derivative financial instrument. What that means is we have to mark-to-market this component every quarter and record that change in value in P&L.

This mark-to-market change is going to cause quite a bit of volatility to our earnings going forward, or could potentially cause quite a bit of volatility. We've decided to add a new non-GAAP measure to our disclosures that's going to take earnings, and we're just going to back out that unrealized gain or loss every quarter.

We believe that's going to give investors a clearer picture of our current operating performance without the noise of this non-cash item.

Excellent. Thanks for explaining that for folks.

That's good. One last question that came in about turnarounds.

Maybe, Todd, I mentioned it in my opening remarks. You could expand a little bit more on how we do this.

Cuz I think it's something we think we're proud of and how we manage our business and how we keep production on, and the uniqueness, I guess, or potentially uniqueness of the way our gathering systems and plants are all connected that allows us to do this. Maybe you could expand on that a little bit more, too.

Sure. Thanks for recognizing the planning that goes into turnarounds, the execution from our asset integrity group, our field foremen, our operators who are out there doing the work when turnarounds are happening.

They do a great job. Sometimes they have to pivot mid-turnaround because we're going into vessels and we're looking and doing UT and that sort of stuff, and all of a sudden we see something needs to be repaired.

They do a great job of minimizing the downtime. Yes, given the interconnectivity, especially down in Braz, we've got three plants that are essentially interconnected.

Then obviously in Sundance, we've got many plants, I think nine in total, that are interconnected. We're able to move gas from plant to plant still seeing some production losses, but it's mitigated substantially.

We did three plants in the quarter. Two were in Sundance, and out of those two plants, we only saw for the quarter about a 400 BOE a day loss on the quarter.

Then the third plant was Brazeau. We were able to divert gas to Chambers and to Aurora, and that only accounted for 100 BOEs on the quarter.

The other part is the modularity of our plants. We might have two inlets at a plant and we've got multiple processing trains.

In a lot of situations, were able to keep part of the plant running and just focus on the part that needs to be inspected. Got them usually in five-year intervals, you might have one inlet that's five years and the other inlet that's sort of opposite or other vessels.

We're able to keep part of the plant running. Not always, but we try that.

We do it by design to minimize the impact on a particular plant at one time. We did one plant at the beginning of Q1, Kakwa, is a small plant.

That went really quick and good. We've got one more here in Q3 starting next week in Swanson.

Same thing. We'll keep about half the plant running.

We'll be able to push a little bit more through one train, and then we'll have gas going up to Nosehill, down to the Edson plant, over to Oldman and Oldman North, and try and minimize the downtime. Big year with five turnarounds.

Yeah. Thank you.

Thanks to the team in the field and everyone that's involved in that. It takes most folks in the office and that to make sure all this runs the way it does.

Looks like no questions. Is that correct, Michelle?

I think we'll end it here. I guess it was a somewhat expected in-line quarter, maybe a little bit boring, but we won't apologize certainly for boring.

Oh, wait a minute, sorry, there is one question now that showed up on our queue. Do you want to take that call?

Hey, apologies, I got my hand raised late there, but thank you for still taking my question, guys. Just on capital allocation, JP, you already raised the dividend once this year, maybe alluded to potential for additional raises going forward.

Just can you walk us through how are you thinking about capital allocation now that you're below your debt targets and free cash flow generation's been pretty strong?

We did have some questions overnight on that, too, I'm glad you did bring it up. As you mentioned, we've essentially met our soft target of debt-to-EBITDA, approximately 1x.

We've increased the dividend slightly last quarter, recognizing that we made it there. That leverage target's backward-looking, of course, and so we're looking forward now, and I've always said that as we look forward, we'll be looking at the business environment to be mindful of where the business environment is.

Gas prices have weakened certainly in the forward strip, we're going to be mindful of that. We're going to remain prudent on our capital returns.

We certainly want to give our shareholders confidence that these dividends are sustainable, and that's just the way we run the rest of the business, too. We'll see as things transpire.

We certainly aren't, obviously still paying down some debt, but we're going to be mindful of the business environment going forward now. We've never paid a variable dividend, and we don't think we get credit for a variable dividend in the market, I don't see us starting that this time.

Any dividend increase we make will be a fixed dividend increase, and we'll continue to do that when we're comfortable with what the forward strip presents to us. That's kind of it in a nutshell, Chris, if that answers your question.

Sure, yeah. Then, excess free cash flow, I guess, would be allocated to the balance sheet in the interim?

At what point, can you give us a bit of color on how low you'd be willing to let leverage go before you find that you have to make a different kind of capital allocation decision?

As we get closer to that, that would be a great problem, wouldn't it be? I would argue that reduction in net debt is a return of capital to shareholders as well.

Either one is a way of returning capital to shareholders. We could go lower.

I tell you what, when we get closer to that level, we'll talk about it.

Got it. Okay.

No problem. Then maybe just a question on the marketing side looking forward, starting in late '27 and more so in 2028, there's more exposure to the WCSB, Empress, Emerson markets.

Wondering how you're thinking about that, just given where your outlook is on natural gas?

Nothing's really changed for us in the way we run the business and our strategy to take risk off the table. Those markets at times can trade just the same as AECO or AECO plus and that's fine.

Depending on the season, we might take that down or not. We might move to downstream markets and make arrangements so we can do that as well.

There's flexibility there over the next, I'd say, year and a half, and we've built this position such that we don't need to react quickly to make these decisions. We obviously don't want to hedge something, say, below $2, and so we're mindful of that, too.

That's our strategy is to continue to add to the hedge book as we see it, as we have a mechanical program that we've prescribed, and we will continue to do that in a mindful way, of course. Nothing really changes for us.

Like I said, we have 400 million cubic feet a day, which is a substantial portion of our future gas out in '28 beyond that's pointed to downstream markets, and so we're not sort of fixed at AECO-only approach. In the meantime, we're well protected on revenues, as I mentioned earlier, if prices really peel away and across the board entirely, then we'll slow down, clearly, right?

Right.

Okay. Then last question, if I can sneak in one more.

Just on the data center side, we've seen the conversation amongst your peers quite active in the last few months. Just wondering if you can give us a bit of color on what you're seeing in that market and is that kind of the opportunity that Peyto might have access to as well?

We certainly have access to it to answer that question. We weren't the first ones to jump onto a LNG deal either, if you recall.

Took our time to find the right deal. We'll be prudent on anything on data centers.

I will remind you that we already have a power deal, right? We already sell our gas, pretty good deal, actually, where we sell our gas to a power plant, it's not like we are desperate for that.

Those opportunities, if they present themselves, will have to make sense to us. We're not going to sign anything just for the sake of signing a deal.

We're not desperate. We're going to look for the right price.

We certainly see a lot of potential, but we'll be prudent again with our approach to this, and we'll make sure that any deal we enter into is good for Peyto and our shareholders.

Okay. Thanks for taking my questions.

Thanks, Chris. Thanks for asking them.

I'll turn it back to you. That's good.

We'll see you everyone next quarter. Thanks for tuning in.