Peyto Exploration & Development Corp. (PEY) Earnings Call Transcript & Summary

Good day, and thank you for standing by, and welcome to Peyto's Year-end 2022 Financial Results Conference Call. [Operator Instructions] I would now like to hand the conference over to your speaker today to JP Lachance, President and CEO. Please go ahead.

Thanks, Justin. Good morning, folks, and thanks for joining Peyto's fourth-quarter and year-end 2022 results 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. In the room with me today to answer any of your questions, we have the entire management team, Kathy Turgeon, our Chief Financial Officer; Riley Frame, our VP of Engineering; Tavis Carlson, our VP of Finance; Todd Burdick, our VP of Production; Derick Czember, our VP of Land and Business Development; and Lee Curran, our VP of Drilling and Completions. By all accounts, Q4 and 2022 as a whole was a very successful year for the company. The team grew annual production by 14% and PDP reserves by 8%. And that, coupled with our higher commodity prices that we realized last year drove record cash flow and earnings for the company's entire 24-year history. But before we get into some of those details, I'd like to acknowledge and thank the folks here in the office for their efforts in achieving the past quarter's and year-end results. We have a small but dedicated team in our Calgary office, and that makes it all happen. Of course, an equal part -- an important part of our success as most folks in the field, the operators, the pharma and the maintenance crews, they keep our wells producing and our plants going. We had a very cold snap just before Christmas where all the hands were needed to keep production on stream. It's always good to see that the percentage of Peyto's lost production during this period was only about half of that of what the industry lost as a whole and to me, that's a testament of our field folks dedication and focus in the field. It's during these cold weather days, when we, as Canadians, are reminded that not only is natural gas reliably heating our homes, but in many other places, especially here in Alberta, Natural gas provides a reliable electric power generation too. In that sense, natural gas is truly like saving energy, and we are proud of Peyto to be one of Canada's top suppliers of it. Okay, enough of soapbox here. 2022 was very much -- it was very much a consolidating interest year, a year where we consolidated interest and expanded our processing capacity, especially in the Brazeau area. Peyto did 2 very complementary acquisitions. One was an underutilized gas plant in Q1 and one was for undeveloped land in Q4. We might get Derick to expand upon these a little bit later and give us some more color on that. But we also constructed the Chambers gas plant, which came on in Q2, and we've continued to optimize that facility up to a capacity now of 65 million cubic -- 65 million cubic feet a day of gas and 2,500 barrels per day of liquids. We have also linked all those plants together in the Brazeau area to provide operational flexibility and total processing capacity now up to 250 million cubic feet a day. We also spent capital to expand and debottleneck gathering systems in Sundance in 2022 to accommodate future growth. I think all told, we spent about $100 million, which was our major facilities in pipelines last year. That's a very large portion of our capital program relative to past years, and we don't expect to spend that this year. Perhaps we'll get Todd to expand upon our facility projects for 2023 later. On our February 16 reserves release, you'll note that Peyto replaced 165% of production with new PDP reserves, and we did it for refining development acquisition costs of $8.46 per barrel or $1.41 per Mcfe where a gas company would like to quote things in Mcfe, which is high by Peyto standards, but still one of the most efficient amongst our peers given the inflationary pressures the whole industry endured last year. We also realized -- we also realized much better prices, including our hedging losses and when you couple that with our industry-leading cash costs, it means we generated a cash netback of $3.74 per Mcfe or 2.7x more than it cost us to have those reserves, which is what we want. We mentioned gas prices were up last year, NYMEX natural gas prices averaged $6.38 per MMBtu, up from $3.84 in 2021. But there was also incredible volatility last year, ranging -- where prices ranged from lows near 350 to highs over $9. AECO prices were also volatile, but with the added challenge of the market disconnection that happens during the summer maintenance season where once again, prices dropped towards 0. And it's for these very reasons, that Peyto has an active hedging strategy to smooth out the volatility, so we can plan our capital programs, commit to paying dividends, and continue to strengthen the balance sheet. It's also the reason why the company has a market diversification program with volumes pointed at various markets like Malin, Ventura, Dawn, Emerson, and Henry Hub, both in the use of various marketing or transportation or basis deals. So what we don't have is essentially any AECO exposure this summer as we expect to see a repeat of last summer's maintenance program. In late this year, we'll have about 10% of our volumes flowing to the newly -- sorry, the newly constructed highly efficient Cascade power plant, which is pretty much close to completion near Edson, Alberta, and that's part of a 15-year gas supply agreement. We're building that pipeline now, and we're excited about [ seeing them ] some gas later this year. As we move forward in 2023, we are taking a cautious approach to our capital spending in light of the fall of natural gas prices. We've built a flexible program that focuses drilling in core areas only, and we've deferred the higher-cost Whitehorse mine head program for now. Starting out a little slower allows us to make the call to ramp up later in the year depending on prices. Prices are in contango, and we are continuing with our systematic hedging program. We're up to about 60% hedged now on average for 2023 at prices near $4 an Mcf, which also gives us that confidence to spend within that capital guidance and sustain that dividend. We also have 25% of our forecasted gas volumes fixed for 2024. So we're continuing to secure future revenues beyond this year. So before we get -- before we open up to questions, I'd just like to point out one more important thing here. The global demand for natural gas continues to grow, and it's never been for energy security than it is today. I read last night that Freeport LNG has approved the start-up of their final liquefaction train. So that's good news on takeaway capacity from the Gulf should pull -- should be a pull on prices there. But there will always be a seasonal supply and demand swing as the commodity is really dependent. And so we should expect to see price volatility to remain. But Peyto is well equipped with our low-cost structure, our price risk management and our disciplined approach to shareholder returns to thrive in this environment as we go forward. Okay. So enough for me. Let's turn the call over to questions. But before we go to the phone lines, I just have one question on overnight that comes in right off the top and we should just address because it's a recurring theme. The question that came in from e-mail and similar to some others, gas prices have dropped in half since you guys set the dividend level last November, are you going to have to cut the dividend? So we do not -- just to be clear, we do not forecast having to change the dividend from this level at this time. Our dividend is still far less than our projected earnings. We have ample protection from our hedge book, and we continue to add hedges in the future that are higher than the prices we have today because of course the forward curve is in contango. If prices roll back -- or sorry, roll forward, we will first look at our capital program, and then we'll make adjustments to ensure we're still making smart, good returns with the money that we're spending. And as I mentioned already, we've already done that. We're guiding to the lower end of our guidance. We're [ trying at ] the lower end of our guidance to pull back and to high grade our projects. So we're deferring the longer payout wells in the facility projects and we expect that the prices do remain low and service costs will realign accordingly as well. So we still have plans to reduce our debt and strengthening the balance sheet is also still a priority. So to answer this question in short, no, we don't currently have -- don't currently expect to change the dividend. So with that, let's open it up to the phone lines if there are questions for folks who want to answer [indiscernible].

[Operator Instructions] And our first question comes from [ Kartheek Raja ] from Bloomberg. And our next question comes from [indiscernible].

Congratulations on the results. I know there's lots of hard work, and I wanted to thank you for that. The topic that I wanted to inquire about is a gap that I think it would be helpful to reconcile the gap. And when I pose the question, I'm really most interested in reconciling that gap in order to understand how that gap might affect 2023. So the question is the target for the firm was 110,000 barrels a day for year-end. In December, the President's letter confirmed that. In January, the President's letter didn't quite confirm it, but basically said that we were on track. There was a little bit of hedging and a little bit of concern expressed about timing. Then in February, and on each occasion, you showed the production in the table. In February, the table showed at 105, which was clearly below the 110, so high marks on transparency about not achieving the target. Then in March, we're at $103 million. And again, high marks on transparency. And I know there's been some issues about deferring production. However, what that leads one to look at is a very strong declaration of the 110 million being intact as of December. And then when we look at where we are today, we are now 1,000 barrels a day as per the March letter. We are 1,000 barrels a day below the Q2 2022 level. And that's -- all these numbers are from the letter. That is despite spending $335 million since Q2 and that's net of acquisitions. I've taken the acquisitions out. So that's a pretty big gap. And I know that there's some inflation in there, and I know there's some in the $335 million, and I know that there's some cold weather in there at the end of the year. But 5 rigs were going pretty much until the end of the year and the money was spent. So I racked my brain and looked through everything to try to figure out why we would have this big gap when all that money was spent and you did touch on it, maybe more on facilities and all the rest of it. But I just was interested in if you could shed some light on the gap. And again, I think you did a great job last year. I just have this topic that I don't understand and what I'm really looking for is for you to look out over the next year and tell us whether or not whatever it was that interfered with production increase over the last 3 quarters, a lot of money on debottlenecking or facilities. Are we looking out over the next year? And is that going to be less of a factor? And you did touch on it in your remarks earlier, but I'd just like you to be a little more in depth on this. And I'm very interested in the answer.

Okay. Yes. So one of the things we put in our reserve release there was the decline rate that we actually experienced. I think part of the reason for the miss in 2022 or at least at the end of the year, was the declines were higher than we thought. And so that was -- or than we forecasted, certainly. So that was one of the issues. You touched on the cold weather, obviously, added to that as well. The latest for a full 2 weeks at year-end, we actually dropped the rig. The 4 -- we do not have 5 rigs running rates at the end of the year, we really had 4, we dropped the fifth rig midway through the quarter. So, that's part of the reason why production wasn't quite as high as we expected it should or wanted it or expected it to be and the decline is a big part of that coming into the year. So that's one of the reasons why we were behind at the very beginning. So, as we move forward into Q1 now, and the rest of the year of 2023, we have 4 rigs running. One of those rigs is dedicated to -- is more or less dedicated to the Minehead and [ there we are doing ] basically drilling earning well. So, we don't get quite the same effectiveness from that rig as we would on production because it's earning at a disproportionate rate. In other words, we spend capital, but we don't get the same results from it. So, that's one of the other reasons and 110, just as a reminder was -- it was a target and we did expect to meet that, and we failed to meet that. And team recognizes that notwithstanding that, we were able to grow production annually by 40% over the year, as you point out, so strong results, just the same but that target was missed. And as we go forward, we are not in any hurry here to bring on a bunch of extra production with prices the way they are. So, we are being cautious and careful on how we're spending our money and whether we bring on production and we've talked about this in February, how we've also looked at doing some optimization maintenance projects and accelerated those into this first quarter because it doesn't make sense for us to bring -- I don't think shareholders want us to blow this -- the top of this initial gas production in Taiwan when prices are relatively poor. We have hedged a lot of volumes. But we don't have them all hedged, right? So, that's the other part of the story. I think I touched on most of what you said. The decline probably is the most significant difference and that's why we're behind coming into the year. Does that help answer your question, Jerry?

Yes, yes. That's very helpful to answer my question. I just -- on the decline, I would just be interested if you could explore that a little more because again, does that mean that if the wells were at Target initial production and then they declined more rapidly, how does that affect the economics overall, and what do you expect of the decline rate in the future? So that would be -- would I think rounded out very nicely.

Yes. So, we actually look at the economics of all of our projects on an ongoing basis. We adjust our type curves, all the time. So, we make sure that what we're doing out there, spending capital effectively is making us money, right? Including the current environment that we're in today. Right? So, we have budgeted or we have planned for a steeper decline in 2023. Right? We've said it was -- it should be closer to 29% based on [ GLJ ]. So, it's going to be in a range, it's around 29% for year-over-year, 29% or 30% let's say. So, we have already budgeted for that and that's part of our model, and just because the wells decline a little quicker at the front end doesn't necessarily mean that their reserves aren't there, and so it's just a profile that we have to better manage here to go forward. But certainly, the economics of these projects are still great even in today's price environment.

And our next question comes from Mike Dunn from Stifel.

Great. Hey just thought I'd ask here if you could maybe flush out a bit for us how you expect the production to look -- I guess through the quarters of this year based on -- I guess your updated outlook to -- may be targeted towards the lower end of that CapEx guidance range?

Yes. So, we expect that we'll -- we could fall a little bit here in the first half of the year depending on what we do through breakup. We do plan to run rigs through a breakup at this point in time it's likely 3 rigs. And -- but will -- that will depend on the weather. To be honest, we've all -- every year, we've gone in with the right -- with a plan and it depends on how spring unfolds to be honest. So, we expect it will be some -- we're going to fall a little bit here. We always do in Q2, just because of the nature of the fact that we don't get as much activity done. And then, but then we'll wrap up in the back end. Of course, the degree to which we wrap up in the back end will depend on prices. That's why we've built this flexibility in there.

Okay. And then another one from me if I may, you now talked about the flare extended reach wells at Sundance, maybe just explain for me how many of these -- you maybe did last year, and how many you're thinking to do in this year?

I'm going to ask Riley to maybe comment on these for us. Riley?

Yes. You bet. So, yes. We drilled a handful of these wells last year. There's a couple of different features typically kind of underdeveloped horizontally in the past. So, being able to go back in and drill these with some longer laterals on the heels of some land deals that were done here to connect some sections and all that stuff is -- has kind of proved up the concept that these tighter channels really do work and they have given us some great results. So, we drilled 4 wells last year and we've already got 2 wells down or 3 wells down this year and we've got another 17 to go this year. So, a pretty good program, and as we mentioned the results that we're getting out of those are really favorable at this point in time. So, it's another benefit of the deal we did a couple of years ago in Cecilia by and large with just another zone that we've been able to extract value out of there. So, yes. They are looking very positive, so.

[Operator Instructions] And our next question comes from Chris Thompson from CIBC.

Hey, everyone. First, one here on cash taxes. How should we think about that for 2023?

Hey, Chris, it's Tavis Carlson here. So, using current strip prices and our planned CapEx spending for the year, we're estimating the -- effective tax rate would be around 10% of the forecasted cash flow. We did end the year with over $1 billion of taxables, that's going to help minimize that tax rate, but the annual deductions on those aren't going to be enough to fully shelter the tax looking forward.

So, on strip pricing, then what's your level of cash tax ability in 2023?

Maybe around 10%, before tax cash flow, yes.

Yes, all right. Okay. And then the next question, what are you planning to do with the excess [ Empress service ] that you have subscribed if anything, maybe you just tell us a bit more about that?

Chris, I think if you look at our marketing slides, you'll see there is a bar on violet that shows the excess Empress service that we have, that we are supposed to get here by the end of this month, we still haven't officially got there yet. It's tranche 5, it's called. So, what we've [ observed ] it's coming. So, when we get that, we basically will then look at ways to monetize that. Last year, I think we saw times of disconnection and AECO was quite large and so when it will be less services relatively cheap it cost us around $0.19 to hold it. And so, anything in the market that [ between ] AECO and Empress throughout the summer, that is greater than $0.19 is going basically add additional funds for us, right? So, it should be a real advantage to have that service but we need to get first.

Got it. Okay. Okay. And then on the service cost side, have you seen any level of reduction in service cost just given where prices have gone in those conversations?

We might have Lee answer that directly but directionally Q1 is the busiest -- it's always the busiest time of the year, right. And I think all the rigs every year, if you look at the history, that's when the rig count is the most of any given year. So, that is one of the reasons why we pulled back that rig last year as we anticipated this. But maybe Lee, so you want to comment anything?

Yes, sure. Nothing yet. Unfortunately, as JP alluded to you. Q1 is a high time for activity. Activity hit a high watermark this year that outpaced a lot of people's expectations. We hit the 250-rig back-of-rig count in Western Canada. So, between that shortage of personnel is still working through some supply chain issues. I think some of those, I think for the most part, that's been sorted out. One of the barriers to I guess deflation is -- it's a bit [ bitter sweet ] but is the impact from FX the Canadian dollar keeps continuing to devalue and so we're competing with our American counterparts for a lot of commodities. So, that's not helping us in any way. We are -- yes, we're working on it. We're hopeful that a lot of our services are recognizing kind of the soft spot in gas prices right now. And it's about a third of the activity out there. So, we're hopeful that come middle of Q2, Q3, we'll see some impact, but nothing material yet, unfortunately.

Got it, okay. Okay. And then on your capital spending plans for this year. How much of that is non-productive capital spending in the budget?

So, I would argue that everything we do and it's productive in some way, it's going to add value to the company. But as far as what's not directed directly. It is not exactly on wells and facilities. Sorry, just one other thing like facilities and whatnot that average is probably around 20%. I mean, Todd, can allude to the fact here, maybe it's a good time to talk about what we have in the facility side. Todd, do you want to [indiscernible] stuff that we're doing is it related to drilling wells?

Sure. So, obviously last year, we had the Chambers plants and that now was a big part of I guess abnormally high facility of projects budget, but this year obviously, JP mentioned that we are working on the cascade connection. So, that's been going really well, no major issues we expect to have the pipeline done here probably in the next 2 to 3 weeks with the vital connections, some facility work that still has to happen should happen in Q2. So, we'll be ready there. So, that's a fairly good piece of the facility or project side. A little bit of plant optimization is planned to happen old man and just some of the Sundance plants and then our regular maintenance. And really other than that we've got some pretty robust production optimization projects that from a cost per Mcf or per BOE are pretty -- I guess advantageous versus what you get when you drill a well. So, not only we get extra production out of that as well. So, and that will help bring up production on the base and stabilize it a little bit. So, that's the key things that we're working on, that should bear fruit through the year.

Any other questions, Chris?

Yes, sorry, one more from me if you don't mind. So, just on the third-party outages coming up this summer. Where are you guys seeing the highest pain points for pricing through the summer?

So, when you say third-party outages, what do you mean [ sorry ]?

Well so, that would be like maintenance on the NGTL pipeline or other facilities that will impact you guys?

Yes. There'll be a -- there is a small outage I believe planes that may affect our NGL volumes will just form up, that's the beauty of us operating our production. We can change the conditions of how we operate. So, that's a smaller one that's happening in.

That's in May.

So, will warm up a little bit. So, we'll put liquids back in the gas phase. And so the heat content extent if the gas prices will be better than but NGTL-wise we have excess capacity on the system. So, we should be able to absorb any kind of maintenance changes if there's FTR cuts of its -- during transportation cuts to that system. And -- but that depends on how NGTL operating system here, [indiscernible] whether they do that or they cut IT to deliveries and predict -- and restrict storage. So, it really depends on how we manage their mix schedule, or how it may affect us, but we are protected in all ways.

[Operator Instructions] We do have a follow-up question. And we have [indiscernible].

Again, JP, the last year, one of the headwinds that was pretty obvious -- was the hedging -- was that prices that when AECO spiked, it led to quite a negative impact which you absorbed well because of the great results, quite a negative impact on the royalty costs. The fact that our hedges are now above AECO or very near AECO is pretty transparent and obvious. And so, I think that's well understood. The part that is less well understood at least by me, I know it exists. But I don't quite know the dimensions of it is the favorable impact that this has looking out over the 2023 year when AECO was nearer our hedges or indeed AECO was below our hedges, there is quite an adjustment, I think to the projected royalty costs, which is a favorable tailwind this year compared to last year. I was just wondering if you could shed a little light on the dimensions of that and the mechanics.

Sure. Yes. So, just a reminder that we pay royalties we pay them on the AECO price, right, the power price, the AECO price basically. So, when we have all this diversification away from AECO and the fact that we have hedges, I would say are fortunately in the money and some cases as we look forward, and I say unfortunately because ideally, we're -- that's not why we're doing it, right? We're doing it to secure revenues, not necessarily to beat the market. But obviously [ had royalties ] are going to be lower with lower prices and so that will be much better than last year. So, that will be helpful, it will be accretive. And since our diversification to all these other markets as you described actually puts us in a better position, which is above, should put us above the realized price. Our realized price should be better than the AECO price, and so that has added a compound effect to our cash flows because we won't be paying as much royalties either. As you pointed out last year royalties work quite a bit higher as a percent, and we also had realized prices that were lower than the AECO at that time. So, it's going to be very accretive I think this year.

Any dimension you can put on that because I know in the worst quarter, we had a $0.95 royalty and it's eased back to $0.75, but the -- and I'm really trying to get at the dimension of the tailwind meaning if AECO has gone down and we're experiencing the decline and the fact that royalties go down, well, we're not better off but if in the forward quarters, the impact on our revenues is only a third of our production, but the impact on the royalties is on 100% of our production with favorability skewed to the hedged portion that grinds out a certain non-proportionate tailwind and it looks like it's well in excess of $0.10, but I don't really know how to model it. So, I'm just back of the envelope $0.10 to $0.20 is the disproportionate improvement in royalties. So, do you have anything on that or we can take it offline?

We can take it offline, maybe we are estimating royalties for this year 9%, above 9% leased on the current strip based when you roll it all in for [ 8% or 9% ] average for 2022 was 11%. So, that put some perspective on the royalty percentage. We can take this offline Jerry if that's okay. I have one more question from e-mail I would like to get to that we never addressed here, Justin. So, I'm going to ask questions for Derick here. We had -- we spend $55 billion last year on acquisitions and that includes Crown land sales were about 20 sections last year maybe Derick you could expand a bit about how we've -- what we've done with those assets, we had a great year in 2021? We bought an asset at Cecilia area we [indiscernible] see it a goal. But we certainly exploded it very well and grew the production in that area. How have we done with the assets that we just bought last year and one was at the end of the year?

We're definitely happy with the acquisition we're able to close in 2022. We typically don't do big flashy deals but [ low deals ] that make sense and profitable. The acquisitions are very similar to Cecilia acquisition you mentioned, [indiscernible] results opportunities, a couple of entry [indiscernible] the corporate acquisition added an underutilized $45 million a day, newer gas plants, I mean, 3 that's actually -- approximately 900 BOE from 20 net wells. On the property acquisition side, we picked up 42 net highly prospective sections that came in approximately 600 BOE a day from 12 net wells, and also 59 kilometers of pipe 50 million a day compressor. We were able to grow this property to over 5000 BOE at year-end post deal in September [ 13 ]. We are continuing to drill the well that we're now pushing past 1000 BOE, we are able to do this because of the incredible fit, so existing land base infrastructure. Also, the [indiscernible] job hiring executing prior to and after closing. And if you haven't done so, I recommend checking on our corporate presentation to do the exceptional fit that these acquisitions provided here. And then on the [ apartment ] side of things, we're in early days, wide apartment and we also started drilling on the [indiscernible] that has created some [indiscernible] over here now. We currently have the ability to [Technical Difficulty] markets and then enter 2023, we continue to evaluate new opportunities and remain opportunistic if the right deal present itself. We always try to at [ somewhere in the fire ] so hopefully we can transact some of those opportunities this year. Also on the assets in front, in addition to doing very active sales evaluating them, we're also very active doing smaller format swaps and cooling to enable growth [Technical Difficulty] This activity has been ongoing already in 2023 and will continue throughout the year.

So, we've been very effective with those smaller deals, not big splashy things, but we certainly have been effective with the small tuck-in type acquisitions as an organization. Okay, I do not think if there is any more questions?

I am showing no further questions over the phone.

Okay. Well, thank you very much for attending the call and we'll talk again soon.

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