Peyto Exploration & Development Corp.

Good day, everyone, and thank you for standing by. Welcome to Plato's fourth quarter 2024 financial results conference call. At this time, all participants on a listen-only mode. After the speaker's presentation, there'll be a question and answer session. To ask a question during this session, you will need to press star 1-1 on your telephone. You will then hear an automatic message advising in your hand space. Please be advised that today's conference is being recorded. I would now like to send a conference over to Mr. JP Lachance, resident and chief executive officer. Please go ahead, sir.

Thanks, Olivia. Good morning, folks, and thanks for joining

Plato'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 Kern, our VP of Drilling and Completions. Todd Burdick, our VP of Production, and Derek Zember, our VP of Land and Business Development. Before we discuss the quarter and the year, on behalf of the managing group, I'd like to thank the entire Plato team, both in the office and in the field, for their contributions to a great quarter and a very strong new 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 release in February. But I think what's most important takeaway is that we delivered on what we said we were gonna 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. 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 the company deliver some outstanding PDP, FDNA costs in 2024 of a dollar in 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 55 cents per MCFE in Q1 down to 50 cents per MCFE in Q4. And a result that didn't prove netbacks. Despite the fact that we lost about 3,500 barrels a day of base production to a Tana. Let's be out done though our legacy lands last year delivered some great results too. We drew a new flare trend right in the heart of Sundance and completed a couple of Takwa flare wells near the end of the year, which came in as expected. The team assembled those Takwa lands over the last few years through a series of crown sales and swaps with other producers. We've always had a large cardian position in Takwa. And these new Spirit River lands along with our gas processing plant really compliment that. We'll monitor the performance of these wells and then we'll go back and we'll drill some more 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 to about 50 million cubic feet a day to match our sales egress in the area. Then 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 for 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 a dollar a share in the quarter. And thanks to cash costs of $1.36 per MCFE, which is the lowest since Q3 of 2023, which is 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 the gas market diversification and our liquids. Now despite the fact that the eco daily price for the quarter was only $1.40 per DJ. 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 that eco on record. When you look at our net backs as compared to our finding costs, we achieved a solid 3.3 times field net back ratio. Where if you throw in all of our cash costs, including our taxes to 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 in 2024 of $258 million to shareholders. And we still managed to pay down a little bit of debt. On the 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 eco. 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 in MCF. And to put that into perspective, the hedge book, including some liquid hedges that we have has secured $850 million of revenue for 2025. What's not secured 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 eco 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 a 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 76 US per M&B to you. And when you look at Henry Hub 2026 summer futures, currently trading at US 417, so $4.17 per M&B to you US. This nets us back about $4.60 a gigajoule at Eko when you subtract the basis and convert the units in the currency, which is about $5.30 per MCF with our heat content. Well, that compares to the current price at Eko on the strip at about $2.89, GJ. And

we continue

to acquire service like this to locations where we 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 cost us roughly $1.15 per GJ to get there. Right now, winter 2526 at Dawn is worth US $4.78 per M&B to you or about $5.28 per GJ landed in Alberta after you include the tolls, to subtract the tolls and do unit conversions. So that's $6 in 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 Millen as well, exposure. So 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 that helps de-risk our revenues. You couple that with our industry leading cash costs and finding costs. It really helps to reduce the volatility of our profits or 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 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 around 27%.

That

should see us exit December of 25 at or about 145,000 BOEs a day using the bid point of that guidance. And we think we can do that with a four-week 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, we 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, it certainly doesn't help the market sentiment or 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 ASO 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. Include phase two of LNG Canada, the Rockies, SLISM's 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 if 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.

Suddenly, as I'm reminded to ask a question, I'm going to press R11 on your telephone and wait for your name to be announced. Please stand by while we compile again your roster. And we have a question coming from Elina Chris Thompson with CIBC Both Markets, Elina is now open.

Hi, Chris, hey, good morning, JP, and Dean, 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 Buies 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 is there a reason why it's higher versus 2024?

Yeah, 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 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 Pato's FTR, service to NGTL, what is your ability to deliver there with respect to the growth program that you have planned?

Yeah, so we have about 15 to 20% extra FTR that we carry, it's part of our transportation costs, it's 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 Edsland 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 have projects that Todd's group will do to help optimize things, but we don't have any sort of greenfield requirements in 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 gonna be more than sufficient for us.

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

Yeah, we'll look at it, certainly.

And then as far as further off-gags reductions, as you noted, they were quite good in 2024. What about 2025, how do we see the cost structure moving this year?

Yeah, we undertook a couple big projects, I'll get Todd to elaborate some more here, but we undertook a couple bigger projects, ones 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 the thoughts are for this year.

Yeah, 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, partially through the drilling program that JP mentioned, more gas coming on in the back half of the year, so with that we'll see operating costs on a per unit basis come down, as far as low-hanging projects out there to reduce operating costs, 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, yeah that's great, and then maybe I'll just throw in one last one here with respect to Kineticore on the Greenlight Energy Center, you know 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?

Yeah, 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 one of those deals to increase our diversification, and we think in long term power is gonna be a, we wanna have that power exposure, certainly we like our Cascade deal, but 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, but we think as we move forward with all the demand that's coming, it's gonna be good to have that power exposure.

Okay,

thanks a lot, I'll hand it back. Thank you.

Thank you. Thank you, and again, to ask a question, please press star one one. And our next question coming from the line of Gerald McKay, yeah, line of the moment.

Go ahead, Jeremy. Yeah, this question has to do with the hedge book. Two parts, first part is, thank you for the update 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, 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 Taito is so hedged, an important consideration as to whether or not things are gonna 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 has improved, it was 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 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 Jerry, I think I got

it, so to answer your first question, how might the hedge book evolve, I think is what you were asking at the end of that, and 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 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 eco 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 GJ, and that was the winner 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 commanding 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 if we're out of the money that would be great, and if right now we're in the money and it 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 yeah the basis is, it takes a while for it, 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 that ACO 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, the 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 park, or sorry the Don deal, we did the 50 million of Don, or the, sorry Parkway, Parkway deal in Toronto, so Toronto area stuff, we've just done that, so that's part of the reason why we cash that as well, so we can compliment our basis deals, I suspect that basis will come in, but it's not there right now, it's not in transport costs, it's quite blown out in fact, when you look forward and that's one of the reasons why we're getting much better price than ACO right now, you're looking at basis that's up, two dollars out there, only two and three seasons out, so that's quite high, it's three dollars right now, so we expect that'll close here though, as LNG Canada comes on.

Thanks, Jerry. Thank you,

thank you.

Thank you, and again as I'm reminded to ask a question, please press star one one, and our next question coming from the line up, Eric Bisslingham with Unconventional Energy Research, your line is now open.

Great quarter guys, and great year out of the 20 years I've been following you guys, just that it sounds like we're talking a little bit too much about hedging, but your thoughts on accessing JKL pricing, -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 tolls 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. Yeah, so I think you're referring to JKM deals to get us exposure to Asian there. I think that's what you were going, you were asking, and yeah, of course, we are looking at options for that, whether it be a net back 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 are continues to add to our diversification portfolio, I mean, a lot of those deals are quite long term. So you might be, might be costing a lot of money, some, you know, during a long period of time. So that's something that we're also cognizant of running our business here. So, you know, we certainly are looking at them, not only just JKM, but really, you know, TTF as well, right? so that's ongoing, but you know, we don't have anything at this point in time. As far as liquid rich M&A, I would say that we wanna be careful that we don't do something that, you know, 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 gonna look at it, whether it be liquids or gas rich. So for us, 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 that has to be complimentary. You look at the Repsol deal we did, and that, you know, fits obviously like a glove. Maybe those opportunities, quite, you know, that obvious are out there, but there's certainly smaller opportunities we're gonna continue to pursue, and Derek 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 up costs are really low. Oh yeah, okay, good, check cash costs. But it's our margins that we still need to pack. I'd encourage you to look at our, at our marketing, our materials on the website, our quote presentation, where you can see where we've actually shown the margins, you know, across with other companies with higher liquid yields. And you can see that that's what's important. So just getting the liquids rich for the sake of adding liquids is not something that we consider. It'd have to be, it'd have to have all the same attributes to do it for any acquisition. At the end of the day, it's about making money, right, Eric? And that may, I come from liquids, and it might not.

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

Thank you. Thank you. And I see no further questions in the queue at this time. I will now turn the call back over to Mr. JP Olshans for any closing remarks.

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

This concludes today's conference call. Thank you all for participating. You may now disconnect.