Peyto Exploration & Development Corp.

Good day, everyone, and thank you for standing by. Welcome to Paytel's first 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 participate, you will need to press star 11 on your telephone. You will then hear a message advising your hand is raised. To withdraw your question, simply press star 11 again. Please be advised that today's conference is being recorded. Now I would like to hand the conference over to the President and Chief Executive Officer, J.P. Lachance. Please proceed. J.P.

Thanks, Carmen. Good morning, folks, and thanks for joining PEDO's first quarter conference call. 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 in the room today to answer your questions, we have Riley Frame, our VP of Engineering and Chief Operating Officer, Tavis Carlson, our VP of Finance and 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. Firstly, we'd like to thank the PATO team, both in the office and in the field, for their contributions to a strong quarter. And Q1 was a good quarter for Payto despite low gas prices. We generated $205 million of funds from operations and $100 million of earnings, which in part has to do with our industry-leading cash costs, but also thanks to a $93 million hedging gain from our systematic hedging program that we put in place over the last two and a half years. This allowed us to not only fund our capital program of $114 million, but pay our shareholders $64 million in dividends and also left us enough to pay down some debt, about $23 million of net debt over the quarter. We continue to be excited by the drilling results on the newly acquired Repsol lands. We had 15 wells on stream to the end of the quarter with enough history that show us a sustained 30% increase of average well productivity as compared to the performance of recent wells, recent years on Pato's legacy assets. This continues to affirm that the assets we bought last year have the quality we thought they did. We completed some very long lateral wells in the first quarter across all species. Longest quarterly program in our history, in fact, at an average length of about 2,200 meters. And we continue to see the benefits of doing this to optimize resource recovery. In Q1, we also drilled two 2,400-meter lateral Dunvegan wells that we subsequently brought on in April. that demonstrate good deliverability, coupled with higher liquid content than our Spear River wells, about 20 to 30 barrels per million. It hasn't succeeded enough to dedicate a rig to the play for the rest of the year. We have over 100 wells booked across our land base, and we expect to drill about 10 to 12 wells total in 2024. You can find a little more information about this in the April monthly report and in our corporate presentation slide deck. Payless focus on unit operating costs remain a priority, so much so that we set a target of at least a 10% reduction from Q1 levels by the end of the year. And we've already begun to make meaningful changes in this regard beyond connecting gathering systems and plants together in the field. The decision to no longer recover ethane via a third-party deep cut plant fits to a T with our own control strategies. Paying someone else to extract low-value ethane from the gas space doesn't make sense, especially when we can redirect a portion of that raw gas stream to our Edson gas plant, which helps dilute its higher fixed costs. We estimate that we will see about a $0.02 per MCFE reduction on overall operating costs going forward without any material loss in revenue. We do lose about 2,000 barrels a day of low-value production from the base, but in the short term, but we expect to more than make up that loss by the year end with the quality of the drilling program that we're executing. And this is a good example that we're running a business here to make money, not lower value BOEs. We're still running four rigs right now, but we have them situated on three well pads for the most part through a breakup to minimize moves and we'll be prudent on spending capital and bringing on production in the current low price environment. That means we might wait on completions to keep costs down and production ads will be delayed accordingly. We have varying levers we can pull to reduce capital should low prices prevail past the summer. I know many are wondering about the status of the Cascade Power Plant and when we're going to start selling gas to them under our contract. As a reminder, that contract is for 60,000 GJs a day or about 52 million cubic feet a day over the next 15 years and it will start once they are fully operational. We have pressured up our pipeline that connects the gas directly to their plant and we're ready to go. Based on publicly available data, both plants have been generating some power and are making commissioning progress, so that's a good sign. The latest filing with the Alberta Utilities Commission for start-up is in July of 2024. When we look past summer 2024 and into 2025, We're excited about the LNG egress build-out, which is coming over the next few years. By the end of the decade, Canada and the US should be exporting at least another 12 BCF a day. Besides that, there's significant demand potential that could be born out of the evolution of AI with increased power requirements for data centers. We all know that natural gas is safe, secure, clean, and affordable, but most importantly, it is a reliable supply of energy for the future. In the meantime, we all While all that comes to fruition, Payto is well protected with our low-cost structure, our disciplined hedging policy, and our quality drilling inventory to thrive in 2024. This gives us confidence to execute a measured capital program, sustained dividend payments to shareholders, and still allow us to manage the balance sheet with repayments of debt over the course of the year. Okay, I'll keep this short, but just a reminder, our AGM is next week on Wednesday, May 22nd at 3 p.m. in our in the building in our Calgary office on the plus 50 level in the conference center. We hope to see you there. If you can't make it, we'll be posting a recording of it on our website afterwards, but please vote your shares. If you need help with that, you can see our press release for instructions. Okay, again, I like to keep this short, so maybe I'll go to the phones. Carmen, if there's any questions there. If not, I can go to some questions we have that came in overnight.

Thank you. I don't see any questions at this time, but as a reminder, if you do have a question, simply press star 11 to get in the queue. I see one question is on the phone. How do you want to proceed? Go ahead. All right. Thank you. One moment while I bring it to the stage. From Chris Thompson with CIBC, please proceed.

Hey, good morning, everyone. Thanks for taking my question this morning. First question for you, just on the transportation costs. In your release, you mentioned you've seen an increase in tolls on NGTL and increase in costs related to transportation with your Q1 results. Just wondering how we should think about that trending for the rest of the year.

Hey, Chris, it's Thomas Carlson here. Yeah, we came out at $0.30 per MCFE in the quarter. And I think you could use that going forward for the rest of the year. I think 2023, we were $0.27. So we're up about $0.03 year over year here. But $0.30 is a good number to estimate for the rest of the year.

Got it. OK, thank you. And then my next question, just in terms of free cash flow for the balance of the year, I'm wondering if you can help us sort of triangulate where you see your free cash flow profile going in the balance of 24.

Well, we don't typically guide specifics on that, but generally speaking, with prices a little bit lower here in the next two quarters, we'll see that come down. Obviously, cash flow will come down in general, and so that might mean we accumulate a small amount of debt over those terms. Q4 we have stronger prices and of course on the strip but also in our hedge book which is in the press release and so we'll see a painful pay down of debt over the years. So the cash flow that we generate obviously goes more than any free cash flow we have and of course sustaining the dividend as well throughout that period is a reasonable problem.

Okay, thank you. And then on the production profile just the loss of 2,000, I guess that would be 2,000 barrels a day of ethane production from your base. But then you mentioned you're going to make up for it by year end. So I understand your exit rate is unchanged. But should we think about, you know, if we were modeling a certain number before this change, would we see our full year average come down 2,000 barrels a day or How should we think about really just modeling this out?

I'd say in the first, like second quarter, third quarter, maybe continuous for that period of time, you'll see a reduction of whatever you had in your model by about 2,000 barrels a day of production. You shouldn't see a change in your revenue. In fact, you should see cash flow go up because we are going to reduce operating costs by, like I said earlier, two cents. So you should model something slightly less on the, obviously 2,000 barrels a day, less on the short term, but depending on the timing of all the production ads we have, which would be Q3, Q4 mainly, and corresponding with higher prices, will more than make up for that 2,000 barrels a day. So it'll be caught up in, say, Q3, Q4, in that range, somewhere in there.

Great. Thanks. I'll hand it back.

Okay.

Thanks for your questions, Chris.

Thank you. You may continue. I don't see any questions at this time. Okay, thanks.

I'm going to take a couple of questions that came in over the wire there last night. Maybe this one's probably for Riley. We talked about the 30% improvement on our well results. You know, we're very happy with what we expected, or maybe it's even a little better than we expected. Can you maybe elaborate some more around, you know, maybe what are the costs associated with these wells, and, you know, how are we predicting where F&D and those sort of things are, a little more color maybe around that program?

Yes. Thanks, JB. Yeah, so obviously the performance of the wells on the Repsol lands have been excellent, as you mentioned, 30% over last year's program on average, which is great. From a cost perspective, everything's coming in in line with what we would expect. Average cost for the quarter, about 4.8 D&C. The Repsol costs were actually just a little bit below that at 4.7 million per well, even though we're actually drilling those wells slightly longer, roughly 15%. Based on the data we have right now to forecast these wells, we're predicting an F&D around $0.95, which is really good. It actually is right in line with what we're seeing from our marble peaks from our reserve process this year. That's all really positive, and I would actually expect that that F&D number here will drop even a little bit further throughout the course of the year as we feather in more punchy Nauti-Cuin locations. As we move through the second half here, we've been able to digest a bunch of the seismic that we picked up late last year, and there's a suite of really high-quality monitoring locations that we'll be drilling in the second half. I expect those numbers to improve through the second half of the year as well.

That's encouraging. Thanks for that, Collar. Todd, I also have some questions around our preparedness for You know, for wildfire season, we saw some smoke roll in over the weekend in Calgary. As a reminder, it is that time. We're hearing about evacuations already in some areas. Maybe you could elaborate on what we learned last year and maybe what we've done or how we will mitigate any impacts from that. It's one of the common questions I'm getting these days. Yeah, sure.

So as far as key learnings last year... We did learn that our gas plants, we can operate them remotely for short periods of time. We can't obviously do that with the Edson gas plant. It's a fairly large facility and a little more complex to operate, but we can run them for a short period of time. Cut off of access is a pretty key issue where obviously if we can't get into a certain area due to an evacuation or something like that, then you've got water tanks that are filling on these sort of things. So again, you can run for a short period of time, but we can remotely shut wells in. which helps so we try and keep things going as long as we can and we did that in certain situations last year. Liquid trucking egress is a main concern that affects many of our plants. Right now about 68% of our liquids move on pipes to sales. As long as those facilities that are on the other end of those keep moving then we can move a large volume of fluid but a lot is moved out on trucks so that's you know some a little bit of risk that we that we see as far as mitigation obviously we talked about it quite a bit we've got a lot of plants linked together especially in the Sundance area and and as well down in greater Brazzo and As we've been talking about since the acquisition, we've worked to connect the Repsol plants in the Greater Sundance area as well. So that gives flexibility to move production around if needed, if a fire should approach a particular part of that Greater Sundance or Greater Brazzo area. We've cleared areas around plants where maybe trees were a little bit close closer than what we felt comfortable with. We looked at all of the rep salts, former rep salt plants, and there was no issues there. Obviously, I mentioned the liquids pipelines. When fires start to get near the area, we start looking at things like pulling tank levels down at plants and LPG levels and that sort of stuff just to be able to to run a little bit longer. And then obviously we installed cameras last year, so we've got cameras at all of the plants so that we've got 360 degree views just to see and make sure that fires aren't getting too close so we can get people out if need be quickly. And then even our propane refrigeration plants, we can always warm up, make less liquid, put it in the gas phase so that we can stretch out that that time while tanks are filling. So, you know, I guess the final thing would be we learned last year that good communication with fire liaisons is really important. At times we were talking to them a couple times a day. They were really good at sending information to us. That allowed us to feel confident that we protecting our people and we're not going to get anybody caught where they shouldn't be so obviously that will be something fires come close we'd be reaching out to those people right away both fire liaisons with industry and with the Alberta government so we feel pretty good that should something come our way we learned a lot last year and made a few changes of what we've done and I think Hopefully we don't have to go there, but if we do, we're ready.

As bad as we can be. Thank you for that. I think it's important for folks to understand that owning and controlling our facilities is a real advantage for us to be able to do these kinds of things, to be able to make the changes we need to in situations like this. Okay, I don't have any more questions. If there are no questions on the call, are there any more questions on the call?

All right, to our teleaudience, as a reminder, that is star 11 if you do have a question. One moment. I don't see any further questions. I'll turn it back to JP Lachance for final comments.

Okay, well, thanks for tuning in, folks. I hope to see you at the AGM next week, but if not, we'll talk again in the next quarter. Thanks for tuning in.

Thank you, everyone. You may now disconnect.