Peyto Exploration & Development Corp.

Thanks, Towanda. Good morning, folks, and thanks for joining Peyto'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 Frame, our Chief Operating Officer; Tavis Carlson, our CFO; Todd Burdick, our VP of Production; Mike Collens, our VP of Marketing; and Mike Rees, our VP 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 team, both in the office and in the field, for their contributions to another strong quarter. Peyto remained active with 4 rigs during the second quarter through spring breakup.

As is typical for Peyto, 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 Mac did cause some oil sands shut-ins that affected demand for natural gas in the province.

And there were some NGTL maintenance that caused prices to go negative, at least for 1 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 BOEs a day, up 8% since second quarter of 2024.

And our cash costs were down 13% over the same period to $1.31 per Mcfe as we continue to lead the industry in that regard. Our strong hedge book added $53 million in total gains, which added $0.75 per Mcf to our realized gas revenue.

And our market diversification contributed $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 $191 million in the quarter or $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 to 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 $0.07 per Mcfe to our sales revenue in the form of other income. Our operating costs were slightly higher, $0.01 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 produce the costs that 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 $40 million of net debt in the quarter and $105 million year-to-date.

So taken together, our cash costs were down $0.11 per Mcfe quarter-over-quarter and $0.19 relative to second quarter of 2024. So all in all, we have the lowest cash cost in town, but more importantly, I think one of the highest in margins as, of course, you know, our low-cost structure and our strong hedging and diversification strategy allowed 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 2 wells we drilled were low working interest, which helped us to test the concept. The next 3 wells that we followed up with in this past quarter, we're 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 costs 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. Wilrich 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 Falher channel trend in the quarter that we discovered last year in the Greater Sundance area. That well has already produced over 1 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 delineate the trend and give us -- give the team more confidence in the 20-plus 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 Edson gas plant via the Central Foothills Gas Gathering System later in Q3 into Q4. And again, 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 go to -- will take gas to Swanson and Oldman. The long-awaited 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 constructive for the basin in the long term, but we should be patient as things ramp up here. In the meantime, we have plenty of production hedged for the summer, about 500 million cubic feet a day, priced at $4 an Mcf.

And the rest of it is diversified to hubs in Eastern Canada and Chicago and the Midwest where prices are stronger. Our business plan and guidance for 2025 remains unchanged.

We plan to spend between $450 million to $500 million to generate production adds at a cap efficiency rate of about $10,000 to $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 had a large number of potent [ non-QM ] locations and more of that new Falher 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 -- as we expect to ramp up production in Q4, which will coincide with better winter pricing and as LNG progresses to full capacity.

But of course, we will remain flexible with our plans as we always are. At the end of the day, we sell a product 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, that we hedge the near term and we -- so that we can confidently fund our capital program, reward our shareholders with profits.

It's simple, it's predictable, maybe perhaps a little boring. But we make no apologies for that.

Okay. I imagine there are some questions.

So Towanda, perhaps we can go to the phones first.

Just to start out, you talked about some of the recent successes at Chambers and the new well -- or 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 now you're adopting?

Yes. As far as the -- I mean, obviously, we mentioned that, I think, last quarter that this is something that isn't something new in the industry.

It's something that others are already doing at least in the oil part of the play. So the concept of going -- drilling a bit lower to the biodegraded zone just helps us with penetration rates, we talked about this last quarter.

And so I wouldn't -- 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 [ turning ] their heads no.

So we might be -- there may be a couple of other companies doing it. So I don't know that we lead, but it's certainly an improvement for us and it's important for our long-term Cardium inventory to get those costs down right.

Okay. And then, 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 $0.07 an Mcfe.

Just 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. But it's not just Brazeau.

Maybe I could get Todd to elaborate on some of the other sort of sources of 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.

Yes, for sure. Definitely some opportunities, some further opportunity in the Brazeau area.

I think we mentioned last quarter when we commissioned that pipeline, we built it so that we can add and we've been -- our JV group has been busy talking to others in the area. And then 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 JV group is pretty active.

We've got a little bit up in Kakwa. So it's kind of spread out all the way from Kakwa down to Braz.

So it's definitely not just happening in Braz, and 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 our -- on the other income part of the balance sheet.

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 as you approach your debt targets, potential shareholder return increases.

Well, we still believe that we're going to put money into the drill bit to grow modestly over the next 2 years. We don't have -- we haven't come out with a formal plan for '26 yet.

Certainly, that's -- it probably is going to look a lot similar to the last 2 years from what we can predict at this point in time. We'll see where prices and everything goes from here.

But -- and we'll continue to make debt repayment a priority, but we have a soft debt-to-EBITDA target of 1x, trailing 12-month EBITDA of 1x. And so that hasn't changed.

And when we get there, which we expect will be sometime in 2026, we'll relook at that capital location strategy. But that depends on where prices are at.

LNG Canada came on and things, AECO price, the differential -- or the basis between that improves, all those things happen, and we'll start looking. And depending on our diversification and all those things, we'll look at where -- 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. But we've got a fairly comfortable dividend level right now that we feel is very sustainable, and we're going to continue to grow.

And nothing really has changed from what we've been messaging all the way along, Chris.

Got it. And then just last question for me, JP.

You touched on AECO improving. How are you thinking about the marketing strategy here?

It looks like your 2027 book has a pretty sizable exposure to domestic benchmarks and relatively light on the fixed, which we expect will increase over time. But how are you thinking about that?

And which hubs do you see as having attractive pricing on the strip that you would be looking at?

We still believe that diversification is important. And diversification doesn't mean not AECO.

But -- so AECO is part of that, and in fact, our exposure to AECO is in the fact that we would like to hedge some of that in the future, right? So as we move closer to '27, we'll build that up because nothing has changed in our hedging strategy plan, right?

When we get to '27, we're going to be -- any season there in '27, we're going to be minimum 50% hedged because we know volatility in commodities is real. As we move forward, we're going to continue to bring up the hedge book in '27.

And when we do that and right now prices in '27 at AECO are pretty good, so 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 and then 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. So we're not -- we think it's good.

We want it to improve. But we're not counting on it as it were.

So it doesn't sound to me like having additional exposure to AECO is -- compared to where you've historically been in the last couple of years is something that you'd be really looking for?

Yes. We're only -- look, remember, we only hedged 2 and 3 years out.

So to the extent that AECO improves, we have a whole lot of reserves that will be exposed to that in the future should AECO really start to run it, becomes, say, a premium market or something different than what it is today, right? So this is a short -- managing things in the short term.

So I don't think -- I don't see us changing our strategy in that regard.

Towanda, I have some questions here from -- that have come in overnight. So maybe I'll just -- if it's okay, I'll ask a couple of those here of the team?

Todd, we did talk about earlier about a little bit the compressor that we're going to install, we've already started construction on next year. Some questions around, okay, what is -- can you elaborate a little bit more?

Where is this? And how is it going to help us?

Sure. So the compressor is, I guess, best described as the sort of the heart of the Peyto Sundance area.

Geographically, township 5321 West 5 for those who are familiar with the area. There's a lot of vertical penetrations in the area, a lot of horizontals and Cardium, Notikewin, Falher, Wilrich.

A lot of depletion. And with the Repsol acquisition, obviously, as JP mentioned, there's a development plan in the area.

And when we looked at it, we said there's a lot of production here that needs to be protected from higher line pressures when you're bringing on these bigger wells. So 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 Cardium and Falher and Notikewin, as I mentioned, that's the bulk of it.

And with the pipeline infrastructure that we bought, along with the Repsol 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 Cardium 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.

So we're going to collect about 30 million to 35 million a day initially. We built the plant so that we can expand it to that 60 million to 75 million cubic feet a day just with another dehy and some more compressors.

We're expecting to see somewhere around a 10 barrel per million uplift on the gas moving either from Swanson, Oldman, Oldman North down to Edson, could be better. It will depend on the species.

And then along with that, as I mentioned, you take -- and I think JP alluded it in the press release, you take 35 million a day out of the gathering system that's going to Edson -- or to Oldman and Swanson, you're going to free up room. You're going to see some flush until we backfill that production with new production.

And as well, all that 30 million a day of gas that you're sending to Edson is now going to be at a lower line pressure, probably half. So that helps the economics of those wells long term.

So a lot of little parts that come in play into the advantage of building this compressor station. Things are going really well.

We're probably 1 month out, maybe a little bit longer until commissioning. We're -- the guys have been -- despite the rain, we've got shut down a little bit and had some delays, but things are moving along really, really well.

Okay. Good.

Thanks. Thanks, Todd.

Another question was about the well outcome so far this year. Maybe I'll get Riley to address that just the whole case.

So we expect some improvements on the back half of the year. Can you talk about the kind of species we're going to be drilling?

Can you elaborate a little more -- maybe just as a little more color on that.

Yes. Yes, you bet.

So when we look 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, 2024, we had a much more Wilrich-centered program in the first half of the year and a much more [indiscernible] Falher-centric program in the second half of the year.

So very similar to '24, I think what we'll see is that curve improve as we move forward through the second half of the year. And 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.

And so I would expect us to be in line with those numbers as we move through the second half of the year.

Okay. We talked about in the press release and I mentioned it here earlier, we're following up on some past successes.

It's not a plays -- a couple of plays that we haven't done in recently. And one of the questions was Viking and Bluesky.

It's not something that people -- I guess, the investors hear a lot about. So maybe I'll get Mike to elaborate a little bit on what we're pursuing there in the Viking and Bluesky here this year later -- later part of this year.

You bet, JP. So it has been a little while since we dipped our toe into the Viking.

We drilled our first Viking well about 2 years ago, and that was a fairly successful first test for us on our lands. And we're looking to wrap up actually the second well through all that in the Viking right now.

So you see a material amount of upside on our land base in the Viking and also on the Bluesky. We haven't actually drilled the Bluesky for a while, I think that goes back about 5 years to 2020.

We did inherit as part of the Repsol acquisition a Bluesky well that Repsol had drilled but we completed. And that turned out to be quite a good well.

So again, material upside in the Bluesky on our existing land position. So we are drilling the first Bluesky well currently and we have a couple more plans for the remainder of the year.

But should the results come in as expected in these 2 zones, we will be more aggressive with them in the future.

Okay. Thanks, Mike.

I don't know if there's any more questions from the phone lines, Towanda?

Okay. Well, thanks for tuning in folks.

We'll see you on the next call in November.