Peyto Exploration & Development Corp. ($PEY)

Good day, and thank you for standing by. Welcome to the Peyto's First Quarter 2026 Financial Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to turn the call over to JP Lachance, President and CEO. Please go ahead.

Thanks, Lisa. Good morning, folks, and thanks for joining Peyto's First Quarter 2026 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, I have Riley Frame, Tavis Carlson, Lee Curran, Todd Burdick, Mike Collens, Derick Czember and Crissy Rafoss and Mike Rees to answer any questions. Before we begin the quarter, on behalf of the management group, as always, I'd like to thank the entire Peyto team that's both in the office here and in the field for their contributions to a record-breaking quarter. Overall, there's lots going on in the world during the quarter, some of which continues today, of course. But we manage through the chaos with a focus on execution like we always do. The record-breaking quarter I mentioned relates to production, funds from operations and earnings, both on an absolute basis, but most importantly, on a per share basis. We spent $150 million in the quarter and still managed to pay down another $89 million of debt, which brings our total debt reduction since the Repsol acquisition in October '23 down by $275 million. Going forward, Peyto is bigger, stronger and financially fitter than ever, which means we feel it's time to give a little more back to shareholders with an increase to the dividend. So let's dive into operations first. We're off to a good start this year. We ran 5 rigs in the quarter across all our core areas. We drilled 23 wells in the quarter over a variety of species from the Cardium down to the Bluesky, investing $121 million on well-related costs less drilling, completing, equipping and tying in. The average performance of these wells are tracking closely with the last 2 years' outcomes, and we're particularly pleased with the latest Cardium drills down in Brazeau. We applied the same drilling and completion strategy that worked so well last year in the Chambers area. And this is where we drill a little deeper in the -- what we call the bioturbated zone to increase drilling rates, greater penetration and then complete the longer horizontals with more stages. The gas rates are better, but most importantly, so are the liquids that come from the wellhead, and that's increased -- that's up to about 500, 600 barrels a day of initial production rates. On the production operations side, we had a busy -- we were busy adding additional strategic pipelines in the field to assist with the development program and to optimize production. And as always, invest in better in our plants with equipment and maintenance to extend the life and increase reliability. All told, we invested $26 million in these projects. The balance of the capital spend in Q1 was used to capture another 41 gross sections of land through direct purchases and crown sales and average attractive rate cost of about $200 an acre. This boosts our drilling inventory and some of this we plan to drill later in the year. Subsequent to the quarter, we have redirected about 75 million cubic feet a day of gas to a third party to increase C3+ recovery. So that's propane, butane and pentanes plus. That adds up to an incremental 1,000 to 1,500 barrels a day at a time when liquids pricing is stronger. This has not come with an increase to operating costs, so it improves our overall netbacks as well. And maybe I'll get Todd to expand upon this a little bit later in the call. Switching to Q1 financials. The continuation of the fifth rig and consistent well results allowed us to grow production to an all-time high of 148,000 BOEs a day and an average of 147,000 BOEs a day for the quarter. That's up 10% over the same period last year or 7% per share. Cash costs in Q1 totaled $1.28 per Mcfe, which was down 10% from the same period last year due to lower interest costs, which would be attributed to less debt and lower rates. We also had lower royalties and slightly lower operating costs down $0.01 per Mcfe. Despite having the lowest cash cost of all the producers, Peyto still expects to lower controllable costs. When I say controllable, I'm referring to operating transport interest and G&A by 10% this year over last year's annual average. That equates to about $0.10 an Mcfe. Flipping to revenue, another strong quarter where our realized price for gas was $4.69 an Mcf or 73% higher than the AECO monthly average of $2.71 per Mcf, which that's adjusted for our average heat content of the gas. The major contributors for capturing that superior price came from a $0.37 hedge gain and $1.61 per Mcf of diversification value. And that meaningful diversification value mainly comes from our purposeful daily exposure to markets in Chicago, Ventura, Dawn, Parkway and Emerson during those cold winter weather events this past winter. So that combination of low cost and great pricing allowed us to put up some very strong cash flow numbers for the quarter, and we had record funds from operations of $293 million or $1.41 a share. Record earnings of $171 million or $0.82 a share, generated an impressive operating margin of 77% and I think the highest profit margin in the last 10 years of 39%. And if you look back over the last few years, the consistency of these margins is what matters most, and it's what gives us confidence in our business model that pays the dividends to our shareholders, grows the company and protects the balance sheet. This strong cash flow led to more debt repayment in the quarter, as I mentioned earlier, $89 million and allowed us to hit our soft -- I'll call it our soft leverage target of 1x debt to trailing 12-month EBITDA earlier than we thought. We're now comfortable delivering more of that free cash flow back to investors and have announced a modest increase to the dividend of $0.01 per share per month or a 9% increase. With this increase, we still expect to retire more debt by year-end at current strip prices, and we'll continue to revisit that dividend level as the year matures, keeping a close eye on future prices in the business environment, of course. Our low costs, our strong hedge position where we've secured $715 million for the balance of this year, that's Q2 to Q4. Another $510 million has been secured so far for '27, combined with that diversification to the multiple markets outside of AECO, it provides us with the confidence in the sustainability of the dividend going forward. Despite the volatility in commodity prices, Peyto remains committed to investing between $450 million to $500 million this year, drilling 70 to 80 wells, net wells. We've slowed down activity for breakup. I think we're down to 2 rigs now, and we'll start up as weather permits, and we plan to run between 4 and 5 for the rest of the year. Modified our drilling program slightly going forward to shift towards more liquid-rich species like the Cardium and the Falher. There's even some oil rich in certain areas that have a little higher liquid content. And remember, we're well protected through the summer with about 70% of our gas volumes fixed at prices just under $4 an Mcf with very little exposure to spot AECO. The rest of our production is pointed to downstream markets. So we'll be watching them closely, and we'll manage gas volumes accordingly. We remain constructive for natural gas with the continued LNG build-out in Canada and the U.S. and the increased demand from local markets like power for data centers. Recent world events remind us the need for security -- sorry, for secure and reliable energy. We know that the gas price market can be particularly volatile. So our mechanistic disciplined hedging will continue. Peyto strategy remains the same, focus on execution, control the things that we can control and that's costs while mitigating the risks on the commodities with both hedging and market diversification. We think that's a winning recipe that provides returns to our shareholders. So before we get to questions online, there's a couple that have come in overnight, one particularly on the deal we did with a third party. I think Todd, I've often said this that we have an allergy to third parties processing. So maybe you can expand upon the reasons why we did that we're sending out $75 million to a third party.

Yes, sure. So obviously, we've mentioned the nice uplift of 1,000 to 1,500 barrels of propane, butane, C5+. With that deal, any liquid ethane has returned back to us as a gas. So there's no ethane in the deal, we can say that. And along with that, like was mentioned, the structure means that we don't see any increase in operating costs, which is great. So along with the, I guess, liquid -- more liquid increased portion of our drilling program this year and the incremental liquid recoveries, we should see about at least a 1% increase in our overall liquid content.

Yes. I guess it's safe to say this is obviously a confidential agreement, so we can't too much, but thanks for the color. Yes. Thanks for the color. Okay. Lisa, why don't we open up to questions from the phone line, if there is any, please.

Okay. Not a problem. [Operator Instructions] The first question today will be coming from the line of Michael Harvey of RBC.

Yes. So just a couple of questions for me. It looks like you hit your longest measured depths in the history of the company this past quarter, helping to drive those better rates you mentioned. Is there more to do in terms of that number, making it even higher? Or have you kind of come close to the point where you're maximizing recovery and balancing with CapEx? And the second one, just on the dividend. Maybe just remind us your methodology there. I think in the past, Darren had always talked about dividends being sourced from earnings, which would imply some more upside, but I think you also have to balance that with your payout and just the lumpiness of the business. So maybe just remind us kind of how you see that in terms of what -- how folks can think about that number going forward?

Maybe I'll answer the Divvy question first, and then I'll turn it over to Riley on the well length question. Certainly, our profits are from our earnings. And we do believe in paying the dividend comes from that. However, we do also want to be mindful of the balance sheet, and we want to make sure whatever we do is sustainable going forward. So I mentioned there at the outset, we have -- we expect to pay at least at current strip prices, expect to reduce debt further here this year. So there's obviously more room should we want to balance this with 100% payout. So there's more room there, but we'll be careful to -- with future strip and make sure that whatever we do is going to be sustainable. The nice part about all this is that we have secured a fair bit of, like I said earlier, of revenue for next year already. And anything out in '28 is actually well above our sort of minimum price. So as we -- as I talked about our mechanistic hedging program will start to take that gas down. So it gives us confidence in the level. So we're going to watch where prices go from here. So there's room to move, as I mentioned at the beginning here in the opening comments. So -- but we'll be careful as we move forward to make sure that's sustainable. Maybe I'll turn another question over to Riley around well length. I think you were asking just can we see continued increases in well length or what's the expectation? So I'll turn it over to you.

Yes. So I mean, I think we'll continue to try and optimize on well length as we roll forward here. But I think a lot of the material gains over the last sort of 5 years have probably been made in that regard. Our land base and our geologic situation is probably more of a constraining factor at this point as far as how long we go with all of our wells. But obviously, we see the benefit on performance. We see the benefit on cost in doing so. And obviously, that has an impact on our per unit metrics. So we'll continue to optimize that going forward. But I would say that we won't see the gains that we've seen over sort of the last several years going forward.

[Operator Instructions] Next question will be coming from the line of Chris Thompson of CIBC.

So just wanted to probe for a little bit more color on the NGL processing agreement there. So this third party is receiving no operating cost change from you guys. So what are they receiving from this?

We're not recovering ethane. So one would think that, that may be an opportunity for them to gain some value because we mentioned that we just -- we're not getting ethane, maybe recovered, but we're not taking that. We're getting that back in the gas phase. So that would be one way. Perhaps I don't know. You have to ask them. And I'm sorry, I can't tell you who they are.

Okay. No problem. But just wanted to clarify, so 1,000, 1,500 barrels a day against our full year number is just shy of 1% of your production. So are we increasing total production? Are we increasing just the mix and hence, the realized price? Like maybe help us understand the modeling implications on that side.

I would just increase your liquid content by 1% is probably the safe thing to do. And as we move through this year, we'll get better clarity on what exactly that number is. We'll also get better clarity on the impact of the Cardium species program that we talked about shifting towards a little bit more. So if you're modeling this, I would say, increase -- just increase your percent of liquids by 1%, as Todd mentioned.

Okay. Maybe just one comment you made in the press release looking at running 4 or 5 rigs for the balance of the year. My read on that was it was fairly noncommittal as to whether it would be 4 or 5. So I was just wondering, JP, if you could expand on how you're thinking about that.

So we're done 2 right now, of course, to break up, and then we'll bring rigs back when appropriate here as weather things dry up out there. And 4 rigs probably puts us to the midpoint of our guidance. 5 rigs probably pushes us to the higher end of our guidance. So if prices improve from where they are, and we see that especially the future prices, not just current prices. So we would look to maybe expand that program to 5 rigs later on the year. We might actually add a fifth rig later in the year, just to set us up for Q1 next year. So that's why there's a range there.

Okay, got you. Are you seeing -- just especially for that fifth rig that is not necessarily part of your steady program, are you seeing much service cost inflation on the rig side?

I'll ask Lee to answer that one. It's right now and things are relatively fresh. I don't know what you want to add something to that, Lee?

Sure. Yes. No, we're not really seeing anything material. Of course, fuel surcharges is in everybody's bottom line from oil and gas operations right to the household. But remember, we are the lowest capital cost producer in the Deep Basin. So we control what we can control. We are seeing fuel surcharges, but we're seeing a reduction in a number of things, including at this point, OCTG, tubulars, rig rates. It's more than offsetting the fuel surcharges we're experiencing. Direct fuel purchases are about 3% of our capital cost. So a surcharge on that isn't really material to the overall program. Of course, it's going to slip into everything else we do, but a little premature to say. And at this point, what's manifesting in terms of efficiency gains is more than offsetting we're seeing associated with spot. [indiscernible]

I guess on the flip side of that, we would be seeing incremental revenue, obviously, if fuel prices stay high, that means oil is high, that means we'll be seeing more revenue. So that will be -- that also will help to more than offset any increase in costs. Todd, do you want to add anything on the op side of it?

Sure. For sure. There's a portion of the OpEx that's exposed to this inflation, probably 15% to 20%, things like chemicals, trucking, obviously, as Lee mentioned, anything that's on wheels, you've got fuel surcharges. And then lubricating oil is obviously directly exposed to the oil price. So we see -- we're starting to see that, especially just here in April, and it may increase our OpEx slightly through Q2, and we'll see how long it goes. But again, those costs might go up, but we see it on the other side as far as revenue from the oil-based component of it.

Okay. Thanks. I just want to make a reminder that we've got our general meeting, it's in person. It's at our building here in the Plus 15 level at a mezzanine level in Calgary. It's next week, Thursday, May 21. If you haven't voted your shares, please vote your shares. There'll be a formal part of the meeting, followed by a brief presentation with the Q&A at the end and followed by some refreshments. So come and get your hat. Are there any more questions? Operator?

At this time, there are no more questions in the queue. I'd like to turn the call back to JP for closing remarks.

Okay. Well, thanks for tuning in, folks. We'll see you next quarter.

This concludes today's program. Thank you for joining. You may now disconnect.