Peyto Exploration & Development Corp.

Thanks, Olivia. Good morning, folks, and thanks for joining Peyto's fourth quarter and year-end 2024 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 to answer your questions today is Riley Frame, our VP of Engineering and Chief Operating Officer; Tavis Carlson, our 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.

Before we discuss the quarter and the year, on behalf of the management group, I'd like to thank the entire Peyto team both in the office and in the field for their contributions to a great quarter and a very strong year. We hit some real highs last year, which are detailed in the year-end press release from last night and the recent reserves report released in February.

But I think what's most important takeaway is that we delivered on what we said we're going to do with the Repsol assets after making that significant acquisition in late 2023. So this time last year, we were already drilling some great wells that continued through 2024 where we drilled a total of 41 gross wells on the old Repsol lands, so that represents about 55% of our total 75%.

And the outcomes from those wells exceeded our expectations by delivering a sustained 40% production improvement over our legacy programs and combined with the near flawless execution in the field helped with the company -- helped the company deliver some outstanding PDP FD&A costs in 2024 of $1 an Mcfe. On the production offside, the team spent a lot of time redirecting gas molecules to different gas plants in the field last year to improve deliverability and liquid recovery.

But they were also able to improve on the costs by simplifying the operations out there. We saved some third-party fees on low-value ethane liquid recovery and we moved that gas instead to the Edson plant to preserve the rest of the liquids.

We also shut-down the sour gas processing side of the Edson plant. And this was a big part of getting our operating cost reduction from $0.55 per Mcfe in Q1 down to $0.50 per Mcfe in Q4, and resulted in improved netbacks.

Despite the fact that we lost about 3,500 barrels a day of base production to attain it. Not to be outdone though, our legacy lands last year delivered some great results too.

We drilled a new flare trend right in the heart of Sundance and completed a couple of Kakwa flare wells near the end of the year, which came in as expected. The team assembled those Kakwa lands over the last few years through a series of ground sales and swaps with other producers.

We've always had a large Cardium position in Kakwa. And these new Spirit River Lands along with our gas processing plant really complement that.

We'll monitor the performance of these wells and then we'll go back and we'll do some work to keep that plant full perhaps later in the year. Over time, if we continue to like the results of those wells, we can expand the plant from 25 million to about 50 million cubic feet a day to match our sales egress in the area and we'll increase the drilling activity accordingly.

With the improvement of US gas prices in Q4, the team continued to bring on new production and we set a record of 133,000 BOEs a day in the quarter. And we achieved our target exit production of 136,000 BOEs a day in December, after deploying $457 million of capital, which is near the low end of our guidance last year.

This translated into a trailing 12-month capital efficiency of approximately $9,700 per flowing BOE which is one of the strongest in our history. On the financial side, we pulled in roughly $200 million in funds from operations or $1 a share in the quarter, and thanks to cash costs of $1.36 per Mcfe, which is the lowest since Q3 of 2023, which just before the Repsol acquisition.

And some good net sales -- a good net sales price of $4.28 in Mcfe, thanks to our hedging and gas market diversification in our liquids, despite the fact that the AECO daily price for the quarter was only $1.40 per GJ. All this culminated into a great year with strong revenue and low overall cash costs delivering a 64% operating margin despite it being one of the worst average annual prices at AECO on record.

When you look at our netbacks as compared to our finding costs, we achieved a solid 3.3 times field netback ratio, where if you throw in all of our cash costs including our taxes, that ratio turns to be about 2.6. By either measure, we think that's a very effective use of shareholders' capital.

We delivered a record amount of dividends for -- in 2024 of $258 million to shareholders. And we still managed to pay down a little bit of debt.

On marketing side, obviously our hedges did us well last year. Recall, we would put those on -- we put those on over the last three years.

And that combined with our US priced market exposure helped us, especially in the fourth quarter, achieve better pricing than AECO. As we look forward, we have hedged 480 million cubic feet a day for this year and 366 million cubic feet a day so far for next year at prices over $4 an Mcf.

And to put that into perspective, the hedge book, including some liquids -- some liquid hedges that we have has secured $850 million of revenue for 2025. What's not secure is mostly floating on markets that price in US dollars in Ontario and the US Midwest.

And of course, the Cascade Power supply deal. We still have a little bit of AECO exposure through our exposure or through our Empress service.

If you look out beyond 2026, at our diversification portfolio, it looks really strong. I would encourage you to check out our marketing slides on the website or in our corporate presentation and they've all been updated as of last night.

One example of the quality of this book is where we have roughly 70 million cubic feet a day of gas volume that's exposed to Henry Hub through basis deals that are priced at US$76 per MMBtu, and when you look at Henry Hub 2026 summer futures, currently trading at US$4.17, so US$4.17 per MMBtu, this nets us back about $4.60 a gigajoule at AECO when you subtract the basis and convert the units in the currency, which is about $5.30 per Mcf with our heat content. Now that compares to the current price at AECO on the strip at about $2.89 a GJ.

And we continue to acquire a service like this to locations where most recently made an arrangement to add 30 million cubic feet a day of physical Dawn exposure starting in November 2025 for a long-term deal, which costs us roughly $1.15 per GJ to get there. Right now, winter '25, '26 at Dawn is worth US$4.78 per MMBtu or about $5.28 per GJ landed in Alberta after you include the tolls after subtract the tolls and do unit conversions.

So that's $6 an Mcf with our heat content. When you combine that new service with our recent Parkway deal, we have about 70 million cubic feet a day exposed to that market.

And on top of that, we also have Chicago, Emerson, a little bit of Ventura and Malin as well exposure. So and of course, we can hedge these markets and we are or we can let them float, but either way the marketing diversification portfolio we have assembled looks pretty darn good.

So all these different sales points in our mechanical hedging program helps derisk our revenues. You couple that with our industry-leading cash costs and finding costs, it really helps to reduce the volatility of our profits, our earnings over the long-term and it should give comfort to our shareholders in our return strategy.

In February, our Board of Directors formally approved a capital budget between $450 million to $500 million which should drill us between 70 to 80 net wells. And add between 43,000 to 48,000 BOEs a day by the end-of-the year next year to offset our base decline rate, which we estimated at around 27%.

That should see us exit December of '25 at or about 145,000 BOEs a day using the midpoint of that guidance. And we think we can do that with a four-rig program, which is designed to hold production flat more or less through the first half of '25, similar to what we've done in past years.

If we have production exposed to low prices, any low prices, you expect us to manage that similarly to what we did this past year where we'll delay bringing it on. And of course we're living in some uncertain times right now with the threat of tariffs on and off again by the month or by the day.

But we think we're well insulated on the revenue side since we have already hedged close to two-thirds of our gas volumes and about 27% of our liquid volumes for 2025. Most of our gas contracts physically deliver in Canada, so we should be US tariff exempt.

But clearly, the uncertainty doesn't help the market sentiment over the rest of Canadians, so we hope this trade war can be resolved sooner than later. On the natural gas macro, there's plenty to be excited about with LNG ramping up in the US already and LNG Canada sometime this year.

The demand right here in Alberta also looks bright with the vast number of connection requests to the power grid to the AESO network totaling near 10 gigawatts of demand, which by my math could be 1.4 Bcf a day of local demand if it was all fired by natural gas. You include phase two of LNG Canada, the Rockies, Ksi Lisims LNG project that we're part of, and the NGTL expansions that are planned to the end of the decade, you can quickly get up to about seven or eight or even nine Bcf a day of new demand by the end of the decade, which it all comes to fruition.

And that's pretty exciting for a basin that produces about 19 Bcf a day. So as I like to say it, I think we're in the right business.

Okay. I imagine there's some questions, Olivia, so perhaps we can go to the phones and take some of those questions.

Good morning, Chris.

Good morning, JP and team. Thanks for taking my question.

The first one I wanted to ask you on just with respect to the capital efficiency you put up in 2024, it's 9,700 BOEs a day. Your guidance implied capital efficiency is higher than that.

So I'm just wondering, is there room to see your actual efficiency be better in 2025 or are there -- is there a reason why it's higher versus '24?

Yes, I would say, there's room, of course, to improve. We didn't -- I don't think we budgeted for 9,700 last year either.

Having said that, though, we did bring a lot of production on at the end of the year, so that year-end exit capital efficiency is, you know, it has a little bit of that sort of extra production that we would have saved throughout the fourth quarter or through the third quarter, I guess, and moved it to the fourth quarter. So I think the 10.5 is a reasonable number still to apply for your models.

Got it. Okay.

And then you mentioned NGTL expansions through to the end of the decade. I'm just wondering on Peyto's FTR, service the NGTL, you know what is your ability to deliver there with respect to the growth program that you have planned?

Yes. So we have -- as we have about 15% to 20% extra FTR that we carry, it's part of our transportation costs embedded in those transportation costs that you see every quarter.

So that gives us room to grow into that. We also sit in an area in the system, which is downstream of all the congestion.

So it is easier for us to get incremental service where we are in Edson in south. So that helps as well.

So we don't see any problems with being able to expand. And of course, we have the processing capacity at our gas plants that also help us to be able to expand without having to spend a lot of extra money.

We got projects that Todd's group will do to help optimize things. But we don't have any sort of greenfield requirements, new plants to accommodate that.

And we think the infrastructure and the build-out of NGTL's plans over the next, I guess, to the end of the decade is going to be more than sufficient for us.

Do you guys intend to add more FTR as NGTL grows and provides that option?

Yes, we'll look at it, certainly.

Okay. And then as far as further OpEx reductions, as you noted, they were quite good in 2024, what about 2025?

How do we see the cost structure moving next this year?

Yes. We undertook a couple of big projects.

I'll get Todd to elaborate some more here, but we undertook a couple of big -- a couple of bigger projects, one that we felt were moving the needle, and of course, increasing utilization is always a big part of that. But maybe I'll let Todd elaborate on what thoughts are for this year.

Yes, sure. So obviously, Q1, we typically see higher operating costs than we would throughout the year.

And then as the year goes through kind of the back-half of the year, we'll see operating costs come down, you know, partially through the drilling program that JP mentioned, more gas coming on in the back the year. So with that, we'll see operating costs on a per unit basis come down.

As far as low-hanging fruit projects out there to reduce operating costs that, we pretty much did most of that this year. We're seeing things like low-power prices, which hopefully stay, that's helping us.

And we're at a time right now where we're seeing the highest methanol costs we've ever seen. And our understanding in the methanol market is we should see that come down.

So that's a fairly significant cost. So we will see things drop off in the back half of the year for sure.

Thanks, Todd. Okay, Chris?

Got it. Yes, that's great.

And then maybe I'll just throw in one last one here with respect to Kineticor the Greenlight Energy Centre, you guys did a great deal with them for Cascade. Have you been in talks with them at all on supplying the new project they're looking at?

Yes, I probably can't talk about anything like that, but obviously, that's part of the 10 gigawatts I mentioned in the opening remarks, there we have -- that would make up that. It would be included in that number.

And I think us or anybody for that matter has opportunity then to -- if it's not directly, I think, in that case, for us it's quite a ways away, so we couldn't directly connect to it, obviously, like we did with Cascade. But we'll look at any kind of -- we'll look at any one of those deals to increase our diversification.

And we think in the long-term power is going to be -- we want to have that power exposure. Certainly we like -- we like our Cascade deal, right now power is, it's a little bit -- it can be up and down every month.

And so sometimes it's great, sometimes it's not. And but we think as we move forward with all the demand that's coming, it's going to be good to have that power exposure.

Okay. Thanks a lot.

I'll hand it back.

Thank you.

Yes, this question has to do with the hedge book. Two-parts.

First part is, thank you for the update to the -- to March, the last snapshot was December. And when I look at your March update, consistent with your earlier comments about the basis deals you have, as you -- the practice has been as you move forward, you fix off of those basis deals and then it gets included in the marketing update.

And in every case or almost every case, it resulted in an upward movement in the level of the fixed hedges. And because Peyto is so hedged, an important consideration as to whether or not things are going to get better or stay the same is the evolution looking forward of the hedge book.

Having said all that, it appears that the hedge book is -- has improved -- is already in great shape, but between December and now for what was taken on, it has moved the forward hedge prices up a fair bit. And given what you said about the existing basis deals you have and the pricing at the hubs that those basis deals operate from, could you just make a comment on if things prevail the way they are, how that might evolve, how the forward book would evolve?

Because it looks to me like you know, we're moving upward fairly substantially. Second part is probably easier.

On the basis deals, when might you start setting things up for 2028, 2027 is very robust and the basis are quite tight. I was just curious if it's a timing thing on 2028 for the basis deals or if it is because basis deals aren't available at the price that you tend to take them at, which is the cost of transport.

Two-parts, second part a little more succinct.

Okay. Thanks, Gerry.

I think I got it. So the answer to your first question, how might the hedge book evolve, I think is what you were asking at the end of that.

We talked about this before, how we are fairly mechanical in the way we do it. We don't have any plans to change the way we do that, and that's -- so that we have some guardrails in there around targets that we like to be at 250 to say 75% to 80% when we arrive at a given season and we start putting that on up to three years in advance.

Six gas seasons as we call it. So we have the option right now and the AECO price in the future isn't that great.

It's not bad though. I mean, we just did some hedges for '27 at $3.50 GJ.

$3.45 GJ.

Sorry $3.45 a GJ, and that was the winter of '26, '27, if I recall. So that hunts for us all day long.

But on top of that, we can hedge that NYMEX basis that we have -- Henry Hub basis that we have as well and command even better price. So we're doing both and we'll continue to do that.

And so the book doesn't really change as we roll forward. We'll continue to add those -- to secure those revenues as we always have.

And for the money, that would be great. Right now, we're in the money, that looks good, but if that changes, that's fine.

We're running a long-term business, not one that looks just one season ahead. So on the second part, you said about the basis deals.

So yes, the basis is, it takes a while for like as you pointed out, we like to get the basis at or pretty close to transport costs. And as we look forward into '28, even '29, that's not there yet.

And I think this will improve, as LNG Canada comes on that should narrow. So we expect acre will improve and that will narrow the basis.

And so there'll be more opportunities to layer in that -- some more basis deals to wherever they are. But that's also the reason why we're doing some physical here because we recognize the basis -- the sort of traditional way of just getting that short-term basis deal is not really available right now.

So we recognize that and we're getting some more physical. We just did the 30 million of the part, sorry, the Dawn deal and we did the 50 million of Dawn or the you -- sorry.

Parkway.

Parkway deal in Toronto, so Toronto area stuff. We've just done that.

So that's part of the reason why we captured that as well, so we can complement our basis deals. I suspect that basis will come in, but it's not there right now.

It's not transport costs. It's quite -- it's quite blown out in fact.

When you look at -- we look forward and that's one of the reasons why we're getting much better price in AECO right now, you're looking at prices basis that's up $2 out there, only two and three seasons out, right, so that's quite high, it's $3 right now. So we expect that will close here though as LNG Canada comes on.

Thanks, Gerry.

Thank you.

A great quarter guys and great year out of the 20 years I've been following you guys. Just it sounds like we're talking a little bit too much about hedging, but your thoughts on accessing JKL pricing vis-a-vis your traditional hedge books and how that unfolds throughout the LNG build-out, shall we say?

And/or would you consider doing a JKL net of processing tools and transport off of the Gulf Coast? And then just secondly, if you had an option to let's say, move into a bit more liquids heavier rich assets, would you consider it given some of the M&A that's just been recently-announced and possible divestitures?

Thank you.

Thanks, Eric. Yes, so I think you're referring to JKM deals to get us exposure to [indiscernible] there.

I think that's what you were going -- you were asking. Yes, of course, we are looking at options for that, whether it be a netback deal or even a percentage of JKM pricing, so we just haven't found what we liked yet.

And so to the extent that balances or continues to add to our diversification portfolio, I mean, a lot of those deals are quite long-term, so you might be -- it might be costing a lot of money some during a long period of time. So that's something that we're also cognizant of running our business here.

So we certainly are looking at them, not only just JKM, but really TTFs as well right? So that's ongoing, but we don't have anything at this point in time.

As far as liquid-rich M&A, I would say that we want to be careful that we don't do something that if there's an opportunity out there, and it makes sense to us, has all the right attributes for any M&A deal, we're going to look at it, whether it be liquids or gas-rich. So for us, it's, you know, we like to see something that has lots of running room, of course, that has or controls its own infrastructure similar to what we do.

And has to be complementary. You look at the Repsol deal we did and that fits obviously like a glove.

Maybe those opportunity is white, that obvious aren't out there, but there are certainly smaller opportunities we're going to continue to pursue and Derick and his team are active in doing that. But I don't, you know, getting liquids-rich just for the sake of adding liquids, I mean, our margins are the best -- our margins -- that's what's important, right?

At the end of the day our costs are really low, yes, okay, good, check, cash cost. But it's our margins that we still need to pack.

I'd encourage you to look at our materials in the website or corporate presentation, where you can see where we've actually shown the margins across with other companies with higher liquid yields and you can see that, that's what's important. So just getting liquids-rich for the sake of adding liquids is not something that we consider.

It have to be -- it have to have all the same attributes that we look for any acquisition. At the end of the day, it's about making money, right, Eric, and that may come from liquids and it might not.

No, I can't disagree with you. Thank you.

Okay. Well, thank you.

Thank you very much for attending the conference call and we'll see you next quarter.