Peyto Exploration & Development Corp.

Thanks Zalonda. Good morning folks and thanks for joining Peyto’s first quarter 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. Present with me to answer questions is Riley Frame, our Chief Operating Officer; Tavis Carlson, our CFO; Todd Burdick, our VP of Production; Derick Czember, our VP of Land and Business Development, and the newest members of our senior management team, Mike Collens; Mike Rees and Crissy Rafoss.

Before we begin the quarter, on behalf of the management group, I’d like to say a big thank you to the entire Peyto team, both in the office and in the field, for their contributions to another strong quarter. And it’s been an event-filled first four months of 2025.

We started out warm in January but got some very cold weather in February across all of North America and that sent gas prices up sharply at many hubs and Peyto was fortunate to have some of our gas pointed at these markets. It’s been very significant.

It also took a significant dent out of Alberta gas storage inventories, which otherwise would have been very full coming out of winter and into injection season. Although, we believe tariffs as they currently exist have a minimal impact on Peyto’s business, the uncertainty of the world economy continues to prevail and it’s likely going to be a bumpy ride for a while.

But despite all this turmoil, it’s business as usual for Peyto and we continue to manage the things that we control like drilling good wells and managing our production operations. Now turning to Peyto specifically, we generated funds from operations of $225 million in the quarter, thanks in part to our gas hedging gains which amounted to about or amounted to $0.83 per Mcf and our gas diversification portfolio which created another $1.13 per Mcf in value.

Together that fetched us $4.17 per Mcf in the quarter or 89% higher than the monthly AECO price. We still lead the industry with the lowest cash costs and with that superior gas revenue of our marketing program, it allowed us to generate a strong 71% operating margin.

Cash costs were $1.42 per Mcfe for the quarter, down from $1.51 per Mcfe in Q1 of 2024. As we continue to realize synergies with the Repsol assets in our operations.

Our operating costs are typically higher in the first quarter due to the extra costs associated with operating in the cold and we expect that they will continue to come down throughout the year, very similar to last year. We spent $102 million of capital this past quarter and the strong cash flow that we had not only allowed us to pay down or to pay out $66 million in dividends, but coincidentally also allowed us to retire about $66 million in debt, net debt.

On the marketing side of our business, our gas diversification to U.S. price markets such as Parkway and Dawn and in the U.S.

Midwest like Ventura and Chicago. We gas point at Emerson, Henry Hub, they all contributed to a sound beat relative to the average monthly AECO price of $1.92 a DJ.

However, Alberta gas pool prices averaged only $40 a megawatt, fetching us a similar price to AECO for the quarter on our direct supply deal to the Cascade Power Plant. And just a reminder, we’re at the start of a 15-year deal there and longer-term as power demand increases, we expect that contract will be quite lucrative.

In the meantime, this is exactly why we want our gas to be directed to multiple markets. So we’re not relying on just one customer, obviously is not a good business model.

Looking forward to the summer and the rest of 2025, we’re excited as most producers are about the prospect of gas heading off the West Coast through LNG Canada this year. We think this will be constructive to the AECO market, but the timing of the startup and the duration to ramp up to full capacity are still to be determined.

In the meantime, we only have a small amount of our gas, our natural gas exposed to the AECO market through 2025. Switching to operations, we drilled 19 wells in the quarter, completed 13 and tied in 14.

Part of the drilling program included a follow-up to the prolific flare channel that we discovered last year. It tested – latest well tested similar to the other two wells on that trend, which were amongst the top decile of our individual well returns that we drilled last year.

And Mike Rees and his team see another 20 plus locations there to drill on that trend in the fullness of time. We also drilled a couple of low working interest Cardium wells in the Chambers area to test a different drilling technique.

It’s new to Peyto but not to the industry. We targeted lower in the zone to improve drilling penetration rates.

Each of those two wells we drilled had 2,500 meter laterals and took about two weeks to drill from spud to rig release. So costs were way lower than our conventional method.

We stimulated each of those with a 60 stage ball drop cemented liner system and they’re flowing back now. We intend to follow-up with a couple more wells later in the year to continue to test this concept.

Why does it matter? Well, 25% of our undrilled 2P reserves are booked to the Cardium and this method could improve the economics of some of those plays.

Facility capital was a little lighter than usual in Q1. We expect Q3 will be a bigger outlay of that part of our business since we have the old man plant turnaround scheduled for September and the construction of a field compressor project in the Obed area.

The will – the Obed compressor project will bring more liquid rich gas to the Edson gas plant via the Central Foothills Gas Gathering System in Q4. We did construct a pipeline project in Q1 that was as part of that capital outlay to connect some third-party gas to the Brazeau plant.

And this is for a multi-year agreement that is strategic and that we can use it for other third-parties in the area too. We have lots of spare capacity at Brazeau and this won’t impact our growth plans there.

Beyond Brazeau, we continue to pursue other third-party volumes in key areas like Edson where we have an extensive large diameter gathering system and spare capacity that could be used. Looking forward, our business plan and guidance remains unchanged for 2025.

As I said earlier, business as usual. We plan to spend between $450 million to $500 million to generate production adds at a capital efficiency rate between $10,000 and $11,000 per flowing BOE by year-end.

And that should be more than enough to offset our annual corporate decline rate of 27%. We think the future is bright for natural gas, especially as LNG projects, LNG Canada and others come to fruition.

We still believe Alberta is the right place to develop data centers and we know that there are approximately 10 gigawatts of projects in the ASOQ [ph] including Wonder Valley. And maybe all these projects don’t get built, but they have the potential to increase Alberta gas demand by 1.3 Bcf a day over the next few years.

So we think we’re – it’s been – it’s a very exciting time to be a natural gas producer in Canada. So with that Tawanda, I imagine there’s some questions that maybe we’ll open up to the phones and take some callers questions about the quarter.

Thanks. Good morning, JP.

Just had a quick follow-up question for you regarding that Cardium well. Was the difference in this well related just to the drilling in terms of drilling lower in the Cardium, just getting better rate of penetration or did you do anything different with the completions as well in terms of the 60 stage ball drop?

Yes. So, yes, we drilled a little bit lower in the Cardium formation as I mentioned earlier.

But yes, we did change the completion up. I’ll maybe get Riley to comment on some more specifics around that.

Maybe Riley, you can elaborate a little bit more what exactly you know we mean by that.

Yes. So I mean the concept of drilling in the bioturbated or lower portion of the Cardium has been around for a while, lots of guys down in the [indiscernible] doing it.

But yes, the big difference is just the rate of penetration that you’re able to achieve in that lower zone is quite a bit higher. The other advantage that we got out of doing it this way was also being able to drill these wells as a true monobore.

So setting a surface casing and then drilling all the way to TD without setting intermediate. So sort of that monobore drilling low and then setting the cemented ball drop liner system are the three main components that really changed the overall design of these wells for us.

And the cost structure associated with those has come in really, really good. So just to give you some sense of it, our drill cost per horizontal meter was 40% less than our historical program in this area.

So as JP alluded to the impact on the go forward Cardium could be fairly significant if we can continue to see success with this. On the completion side, aside from the size of it, just fairly standard completion typical to what we would normally pump, except just obviously scaled to 60 stages that we ran in the wellbore.

Okay. So with the longer lateral, like 60 stages on a ball drop is still fairly effective, like you don’t get to an issue of the small ball sizes.

We definitely, like – there is definitely frictional issues towards the end of the lateral, but we’re still able to pump at rates that are comparable to what the guys are doing with the coil shiftable. So we didn’t see too many issues and we were able to place everything that we wanted to in this well at 60.

Okay. Okay.

And I appreciate the color. And then just a second question, more on the hedges.

I know you have a diversified program and you layer in hedges regardless of the gas price. Just curious, what is your target for percentage hedge for given that you’re now starting to layer in 27 hedges.

So just curious what your target would be for 2026 and 2027 by the time we get to the end of 2025 in terms of percentage hedge that you’d like to be.

Yes. As a reminder, the mechanical nature of our hedging program is such that we want to land in a current season anywhere between 50% to say as much as say 80% – 75% to 80% hedged, volumes hedged once we arrive in that season.

But we’re going three years out, so six seasons out, six gas seasons out, so we will time it such that we’re doing this fairly regularly, routinely, not at any price, we do have some lower end targets. We’re not going to hedge gas at $2.

But certainly as we move forward, we’re going to continue to hedge out 27 [ph] and bring that up in the curve as we get closer and closer to it. So that way we’re not speculating on price.

We’re doing this – we’re doing it systematically over time. So like dollar cost averaging, right?

So that hasn’t changed. Nothing’s changed on our strategy.

So our guardrails, as we like to call it, are 50% to say 75% in the current season when we arrive. And that tapers down as we move out in the future over the next three years.

Okay. Sounds good.

Thanks for the color.

Yes. We do have some other questions that have come in here overnight or certainly live from yesterday.

So maybe I’ll turn to Todd for one here. It’s about operating costs.

Look, we were down at $0.50 per Mcfe last quarter. We’re down from year-over-year and I know our costs usually fall down will drop throughout the year.

We have a history of doing that. But you maybe you want to provide some more color on how you’re going to get there, Todd, as we move forward throughout the rest of the year?

Yes. Sure.

Yes. Obviously like you mentioned, Q1 typically higher, Q2 can be little around the same, maybe a little lower depending on how breakup goes.

Obviously, we’re hauling water at half loads, so you’ve got twice the trips and twice the cost on that side of things. So that’s we’re quickly coming out of breakup here, so we should see those costs improve.

But we continue to work on small projects within the Edson Gas Plant that are aimed at reducing costs at the plant, including we recently completed a project that allows for delivery of produced water into the plant and then onto the plant’s disposal well. So we expect that will result in a modest reduction to our water handling costs as we sort of understand better the compatibility side of water and that sort of thing.

We expect to expand the – I guess area around the plant that we’ll be able to bring water in instead of bringing it to third party processors and disposal companies. Additionally, we also made some changes to some of our maintenance contracts at a few of our gas plants which should help with a small reduction in some of the plant maintenance costs.

And then on the chemical side, in May, we saw a 10% reduction in methanol costs, which is encouraging given we saw about a 25% increase over the past year. While we’re cautiously optimistic, obviously, you mentioned the bumpiness of the world markets and methanol is sort of tied to the world economy in some ways.

So we don’t have a clear line of sight if those prices are going to continue to drop or even hold where they are currently. But we’re cautiously optimistic on that front.

So you put all those together. We’ve – it’s small little gains that we’re getting right now.

We’re not getting big gains by shutting in sour production and things like that, but we’re continuing to push and work on it in fractions of a penny if you will.

We’re always done.

That’s right.

Okay. I don’t see any more questions on the callers list.

So I might just wrap it up here for folks because we all got work to do. So thanks for tuning in.

Remember our AGM is next week, Thursday, May 22 at 3:00 p.m. It’s in our building on the Plus 15 level.

It’s an in-person meeting and we’ll – we’re not telecasting it live, but we’ll record it and we’ll put it up on the website later. So vote now if you haven’t already, and we’ll see you at that meeting or see you on the next conference call.

Thank you.