Peyto Exploration & Development Corp.

Good day, everyone, and thank you for standing by. Welcome to PaytoSupport Quarter 2024 Financial Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will 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 you in your hand or face. Please be advised that today's conference is being recorded. I would now like to send the conference over to Mr. J.P. Lachance, President and Chief Executive Officer. Please go ahead, sir.

Thanks, Olivia.

Good morning, folks, and thanks for joining Payto'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 management group, I'd like to thank the entire PAO 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 release in February. But I think what's most important takeaway is that we delivered on what we said we were 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. That represents about 55% of our total of 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, FD&A costs in 2024 of a dollar in MCFE. On the production ops side, 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 cost 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 it resulted in improved netbacks, despite the fact that we lost about 3,500 barrels a day of base production to Atena. Lots 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 CAQA flare wells near the end of the year, which came in as expected. The team assembled those CAQA lands over the last few years through a series of crown sales and swaps with other producers. We've always had a large cardium position in CAQA, 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 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 U.S. 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 a good net sales price of $4.28 in MCFE, thanks to our hedging and the gas market diversification in our liquids, despite the fact that the equal 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 ACO 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 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 put those on over the last three years, and that, combined with our U.S.-priced market exposure, helped us, especially in the fourth quarter, achieve better pricing than ACO. 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 U.S. dollars in Ontario and the U.S. Midwest and, of course, the Cascade Power supply deal. We still have a little bit of echo 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 76 U.S. per MMBTU. And when you look at Henry Hub 2026 summer futures, currently trading at U.S. $4.17 for MMBTU U.S., this nets us back about $4.60 a gigajoule at ACO when you subtract the basis and convert the units and the currency, which is about $5.30 per MCF with our heat content. That compares to the current price at ACO on the strip at about $2.89 GJ. We continue to acquire service like this to locations where most recently I 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 improve the tolls, after you subtract the tolls and do the 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. 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 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 to $500 million, which should drill us between 70 to 80 net wells, and add between 43,000 to 48,000 BUEs 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 BUEs 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 U.S. tariff exempt, but clear to the end 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 U.S. 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. You include phase two of LNG Canada, the Rockies SLISM 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. 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.

Certainly. As a reminder to ask a question, you need to press R11 on your telephone and wait for your name to be announced. Please stand by while we compile it on your roster. And we have a question coming from the line of Chris Thompson with CIBC Bold Markets. Your line is now open.

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 BUIs 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 24?

Yeah, I would say there's room, of course, to improve. 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, 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, you know, what is your ability to 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 Edson and 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 going to 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-ex 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 of big projects. I'll get Todd to elaborate some more here. But we undertook a couple of 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 on, 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, you know, 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, you know, low hanging fruit projects out there to reduce operating costs. We pretty much did most of that this year. You know, 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 Kineticor 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, you know, obviously that's part of the 10 gigawatts I mentioned in the opening remarks there we have that will make up that. It would be included in that number. And I think us or anybody for that matter has opportunity then to, to, if it's not directly, I think in that case, you know, 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, to increase our diversification. And, you know, we think in long-term power is going to be a, you know, we want to have that power exposure. Certainly we like our cascade. Now power is, you know, it's a little bit, it can be up and down every month. And so, you know, sometimes it's great, sometimes it's not. But we think as we move forward with all the demand that's coming, it's going to be good to have that power, you know, exposure.

Thanks a lot. I'll hand it back. Thank you.

Thank you. And again, to ask a question, please press star 11. And our next question coming from the line of Gerald McCahey.

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 as you as you the practice has been as you move forward you fix off of those basis deals and and then that 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 PAYTO 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 has improved. It's 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 prevailed the way they are, how that might evolve how the forward book would evolve because it looks looks to me like you know we're moving upward fairly substantially second part is probably easier on the basis deals uh when might you start uh setting things up for 2028 uh 2027 is very robust and and the bases are quite tight um 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. To answer 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, 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. We have the option right now. The ACO price in the future isn't that great. It's not bad, though. We just did some hedges for 27. at $3.50 a GJ. $3.45 a GJ. Sorry, $3.45 a 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, the Henry Hub basis that we have as well, and command an 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, you know, to secure those revenues as we always have. And if we're out of the money, that would be great. 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. As you pointed out, we like to get the basis at or pretty close to transport costs. As we look forward into 2028, 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, you know, 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. 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. And 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, we cashed 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 a transport cost. It's quite a, it's quite blown out. In fact, You know, when you look forward, and that's one of the reasons why we're getting a much better price than ACO right now, you're looking at prices, you know, basis that's up, you know, $2 out there, only two and three, you know, seasons out, right? So that's quite high. It's $3 right now. So, you know, we expect that'll close here, though, as LNG Canada comes on.

Thanks, Jerry. Thank you.

Thank you.

Thank you. Again, as a reminder, to ask a question, please press star 1-1. And our next question, coming from the line of Eric Bislingham with Unconventional Energy Research, your line is now open.

Great quarter, guys, and a great year out of the 20 years I've been following you guys. It sounds like we're talking a little bit too much about hedging, but your thoughts on hedging you know, accessing JKL pricing, these of the, uh, your traditional hedge books and how that unfolds throughout the LNG, uh, build out, shall we say, and, or would you consider it, uh, you know, doing a JKL net of, uh, processing tolls and transport off of the Gulf coast. And, uh, then just, uh, you know, secondly, um, If you had an option to, let's say, move into a bit more liquid, 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 Asia there. I think that's what you were going for. 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 one we like 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 costing a lot of money during a long period of time. So, that's something that we're also cognizant of running our business here. We certainly are looking at them, not only just JKM, but really TTF as well. 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. For us, 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 complementary. You look at the Repsol deal we did, and that fits obviously like a glove. Maybe those opportunities, quite that obvious, are out there, but there are certainly smaller opportunities we're going to continue to pursue, and Derek and his team are active in doing that. 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 op 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 marketing materials on the website, our 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'd have to have all the same attributes to do with forehand 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, can't disagree with 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. J.P. Lachance 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.