Peyto Exploration & Development Corp

TSX:PEY

Earnings Call Transcript 2022-Q3

[Operator]

Good day, and thank you for standing by, and welcome to Peyto's Q3 2022 Financial Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Darren Gee, Chief Executive Officer.

[Darren Gee, executive]

You kind of cut out there a little bit, Justin. Hopefully, we're still all with you. Good morning, ladies and gentlemen, and thanks for tuning in to Peyto's Third Quarter 2022 Results Conference Call. Justin, can I just confirm that we're coming in loud and clear?

[Operator]

Yes, sir. Did you not hear my introduction? I apologize.

[Darren Gee, executive]

Not a problem. You just cut out at the end there. I just wanted to make sure we didn't lose the line.

[Operator]

You are live.

[Darren Gee, executive]

We're all good. Super. Well, thanks, everybody, for listening in. Before we do get started today, I would like to remind everybody that all statements made by the company during this call today are subject to the forward-looking disclaimer and advisory set forth in the company's news release issued yesterday.

In the room today, we've got the entire Peyto management team. Our President and Chief Operating Officer JP Lachance is here to answer your questions; as is Kathy Turgeon, our Chief Financial Officer. We've got Scott Robinson, our VP of Business Development here. Dave Thomas, our VP of Exploration is here. Todd Burdick, our VP of Production; and Lee Curran, our VP Drilling and completion are both here to answer your questions on operations. Derick Czember, our VP of Land; and Riley Frame, our VP of Engineering are here; and our new VP of Finance, Tavis Carlson, is here. Everybody is in the room ready and set to go for your questions.

Before I get started with my comments about our results though, I do want to recognize the efforts of both our office and field personnel this past quarter. We had a very active quarter of drilling and completions, pipelining activity, we had some land deals, some acquisitions. We were busy firing on all cylinders. Even our marketing guys were hopping this past quarter with all the volatility in commodity prices and egress opportunities that existed. And of course, our exceptional field staff kept everything running smoothly, so a big thank you to all of those for that effort, particularly now since it's 20 below in Alberta and we all rely on natural gas to keep the lights on and heat our homes and survive the winter. So on behalf of all Albertans, thank you all for giving us that security.

And I suppose, speaking of security and the freedoms we all enjoy, I would also like to thank all those that have fought so valiantly to give us that freedom. Tomorrow is Remembrance Day, which is the official day to remember, but we are thankful every day for their sacrifice. Please remember them with us.

Onto the quarter. As we mentioned in the release, we drilled in most of our core areas and into many different formations in the quarter. And that's important because as we diversify, both geographically and in geology, we eliminate a lot of the contingencies between wells, and we tend to reduce the risk in our overall drilling program. It really allows us to pick the very best of each area in each area and in each zone. And those results are starting obviously to show now. We drilled some great Dunvegan wells in our Cecilia area, which is a new play for us, and we drilled in several different zones in Brazeau that proved up even more of the future inventory down there.

Our average well in the quarter was almost 5,000 meters measured depth, which is the longest we've had on average. And that's amazing. Over 1,600 meters of horizontal lateral on average. And of course, that average was up because a large percentage of wells in Brazeau, or were in Brazeau, and the formations are very deeper there, so we have to drill a little bit deeper to get to them. Our average well cost was also a bit more expensive because of those deeper wells, but there are some big wells down in Brazeau to make up for it, so there's a reason we're going deeper.

We also saw our costs on a per stage and per meter of horizontal lateral were up, partly due to service cost inflation and partly due to increased frac intensity. Because of the increase in more expensive wells that we've chosen to drill in Brazeau, and because we've built a disproportionate amount of facilities and large diameter pipelines this year, we've had an increase to our capital budget for this year, but that's okay. Riley assures me that the rates of return we're generating on all these wells in Brazeau are fantastic. And some of these new plays, we're proving up and all of this infrastructure we're investing in will serve us well for many years to come.

We also closed a very strategic property acquisition in Brazeau during the quarter with some very exciting drilling inventory on it. In fact, we've already drilled 2 big wells on those new lands and they were brought on just this week, I believe. That's nice that we can jump on those opportunities right away. These new lands plug in quite nicely to our existing land base and we'll use a lot of this inventory to fill up the Aurora gas plant that we purchased earlier this year. There's a good slide in our corporate presentation that illustrates where all these lands and facilities are and how well they fit in, so please check that out.

On the financial side of things, commodity prices, particularly gas prices, were wild during the quarter, or at least AECO was. The daily AECO high in the quarter was I think over $6.50 a gigajoule, and the low was negative $0.19, so extreme volatility, which is exactly why we've chosen not to have any exposure to the AECO market. The NYMEX was much more stable. It had a daily low of $5.65 and a daily high of $9.85 and the average was I think 7% higher than the previous quarters, so a lot more stable there.

Although we have almost no exposure to AECO, we did have some previous hedges to contend with, which is why our realized price is still lagging the spot market. We'll all be glad to put those behind us, which is also why we expect such a nice jump in funds flow for next year despite a lower strip price as those hedges roll off.

Of the things we do control, we did a good job. Our cash costs before royalties were right in line with the previous quarter at $0.87, a bit higher transportation costs, offset by a bit lower interest cost. We are forecasting our interest costs will continue to fall as our debt falls, and that's despite the rising interest rate environment. We signed up a new bank deal in Q3 that comes with it lower stamping fees, so that will help offset the rising Bank of Canada rates.

The future strip for both oil and Alberta Power has both of them falling into the near future, so I guess that's helpful for our operating costs as both oil price and diesel and Alberta Power pool prices drive a lot of our operating costs. As we continue to fill up our gas plants and increase utilizations though, we should see some improvement in op costs on a per unit basis. But the reality is, we use a lot of diesel to run the trucks and heavy equipment in the field, including drilling rigs and frac pumpers, and everybody driving around to develop all this natural gas, and that's driven by oil price. Higher oil prices do drive higher costs for us.

We've been watching closely the evolution of natural gas-powered equipment like drilling rigs and frac pumpers and CNG or LNG powered semi-trucks. We're eager obviously, to adopt those to use the fuel that we produce when they are ready. But as of yet, the economics just aren't there. Lee has been following that closely, so feel free to ask him a question about that if you'd like.

Overall, our financial performance in the quarter was good. But as I mentioned, it will be so much better when our hedges roll off and we don't have a $92 million hedge loss in the quarter. As it was though, we achieved a 71% operating margin and a 30% profit margin, and those are going to help to drive record cash flows and earnings for this year. And despite the extra $26 million in capital outlay for the acquisition in the quarter, we still reduced our debt in the quarter. That's 8 straight quarters we've reduced our debt, and we plan to keep knocking it down until the amount that we really have exposed to any higher interest rates is significantly reduced. Remember though, we have around $420 million of debt that has fixed interest rates on it. That's about 45% of our debt right now, and those fixed interest rates are right around 4%, so that portion has no risk of rising rates associated with it.

We also announced our plans for 2023 yesterday, and that's exciting. We've got a great lineup of drilling plans, but we're going to schedule it to try and take advantage of a less busy summer season so that we're not competing with all the winter guys and the winter only drilling that happens in the province. We'll be following up on our successes this year in Greater Sundance and Greater Brazeau as always, and also building out a brand-new core area that's in between those 2. It's called White Horse. We announced some details about that in yesterday's press release as well and there's also a good slide in our presentation that shows where that is. We're excited to get on to those plans.

And then, of course, lastly, we announced a return to a much higher dividend for 2023. And I'm sure many of our long-standing shareholders are happy to finally see that. Of course, that doesn't we're abandoning plans to continue to strengthen our balance sheet. It just means our free cash flow position for next year is expected to be even stronger than this year, so we can finally start to flow some of those outsized earnings that we've been generating out to our shareholders, or the profits that we've been generating on all this capital we've been investing.

And of course, we fully recognize some of the extreme commodity price volatility that we've had over the past few years, which is why we need to have the security of pricing going into the decision to increase the dividend. We now have over 50% of our gas sales for next year already sold. And with that hedge protection, we know we can fully fund our capital program dividend even if the spot price drops well below that $3 per MMBtu. And since we're only exposed really to NYMEX prices, that's the price we're watching. Spot prices right now though, for next year and the futures curve for next year, has been cycling right around that 550, so substantially more. And that's why we're quite confident in the funding that we have going into next year. But we will continue with our hedging practice of locking in future prices as we move forward in time to ensure that we all have that funding going forward.

Anyway, that's a lot of talking for me. I'm sure investors and those listening in have lots of questions. Justin, maybe I'll stop and we can turn it over to questions from those listening in.

[Operator]

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

[Christopher Thompson, analyst]

My first one for you, how are you thinking about natural gas egress capacity out of the basin after the maintenance disruptions that we saw this past summer? And then as a follow-on to that, can you maybe walk us through the mechanics of how Peyto's gas molecules flow to market?

[Darren Gee, executive]

Sure. JP, do you want to...

[Jean-Paul Lachance, executive]

Yes, sure. Good question, Chris. Yes, so as you know, we're very diversified. We have got a lot of our gas pointed to different markets. And we've done that in different ways. One of the ways, one of the locations we're pointing to is Emerson. We have physical transportation that covers us to get to Emerson. And with that, we also have the Empress piece. This is the piece that gets across the border from AECO into the mainline. We have those physical transportation contracts to last us for pretty much as long as we like. The Emerson deal is a renewable contract, so we're allowed to renew that every year. And then we have more than enough Empress to cover that piece of the transportation and then some, and that gives us some flexibility so that we could sell either at AECO and/or at across the border into Empress for relatively cheap insurance.

But the rest of our diversification, as you know, is more around basis deals or what we like to call synthetic transportation. That's to these other locations like Henry Hub, Malin, Ventura, Dawn. And those are all set up with marketing arrangements that get us to price at those locations, at those markets, but how we get there is embedded in marketing or basis deals. We really only have to physically deliver into the NGTL system here in Alberta. That allows us to maybe not take on those long-term transportation arrangements in that case. And by doing that, we just have to make sure we have enough physical transportation here in Alberta. We have about 15% or 20% excess firm in the NGTL system right now and so that allows us for the future growth of the company as we see going forward.

Come next year, near the end of next year when we start delivering to the Cascade power plant, we'll have an additional, a minimum of additional 50 million a day of capacity that we will have, that we'll have available as FTR service as we bring that gas directly to -- from our Swanson plant directly down to the Cascade power plant. From a transportation perspective, we've got more than we need and ability to grow into that. And the nice part about this too is, we basically are diversified away from AECO, so we won't be subject to the summer price swings that we see. And as Darren mentioned earlier, how prices go negative in the summertime.

[Darren Gee, executive]

Chris, I'd add that I think NGTL just released the maintenance schedule for next summer, maybe surprised everybody at the amount of impact that's going to be happening to the system. And really, their mechanism for dealing with too much power in the system when they're trying to do that maintenance is obviously to cut the access to storage. And that's where the price gets very volatile. Thankfully, we've got coverage for all of our volume and then some actually to be able to get out of the province and not be exposed to that price volatility, particularly in the summertime. We signed up, as JP mentioned, several years ago for a whole bunch of service, delivery service, off of Nova onto the mainline, that gets us all of our gas and then some. We've got lots of coverage, lots of protection against the impact of things like that being in the schedule and the volatility it creates.

[Christopher Thompson, analyst]

Okay. Just to clarify on the comment on having coverage for your volumes, so that's 10% to 20% of FTR in excess of your gas production according to 2023 guidance?

[Jean-Paul Lachance, executive]

Correct. That's the FTR to get on to Nova, receipt service to be able to deliver on to NET. And then of course, once you're on Nova NET, then you're exposed to the AECO price. How do you get away from that? Well, then you've got to have the diversification, either the basis deals or the firm service, delivery service off the Nova system to get outside of the AECO market. We have both pieces, in excess actually.

[Christopher Thompson, analyst]

My next question for you, what percentage of your 2023 capital spending will be directed towards facilities and pipelines?

[Jean-Paul Lachance, executive]

Yes. I can. About the same as we did this year. We have a few, this is JP, we have a few major projects we still have planned for next year. We have the Cascade pipeline I just mentioned that we have to drill down to as to the power plant. How far is it roughly about?

[David Thomas, executive]

About 21 kilometers.

[Jean-Paul Lachance, executive]

Yes, so a fairly large diameter line down 21 kilometers. And then we have the plant, although we're saving some costs on the plant like leasing some equipment, we still have a fair bit of cost to spend there. It's roughly going to be around that same range, Chris, in that 15% to 20% range. Probably closer to the 20% range in our budget.

[Christopher Thompson, analyst]

Okay. And then where do you see cash taxes coming in for 2022 and then 2023?

[Darren Gee, executive]

I think we're budgeting right now a little bit of taxes just here in the fourth quarter to end the year, a small payment. And then next year, we're going to start making quarterly progress payments on our tax bill as we move throughout the year. We're obviously still converting pools that we've accumulated through our capital historically as we go along. And then the capital program next year also adds to that base. But we just don't have enough obviously to shelter all of the income that would be taxable in the year, so we will pay some tax. I think we were looking at an average of somewhere around 12% of cash flow.

[Christopher Thompson, analyst]

Okay. And then final question, and I think you may have mostly answered this, but in terms of how you think about dividend sustainability in your capital program, I think I heard you say down to $3 per MMBtu NYMEX in 2023?

[Jean-Paul Lachance, executive]

Yes, even less, in fact. We run a bunch of sensitivities on commodity price. Obviously, we want to make sure that we can fund all that we want to accomplish. And debt reduction is one of the things we do want to accomplish, so we want to make sure that we've got the free cash flow for that and the dividend and obviously to fund the capital program. Now, if we did see a large drop in the commodity price, likely we would see a follow-on drop in service costs. The expectation is our capital program wouldn't cost us quite as much because we'd see everything backing out. Activity levels, if commodity prices drop, tend to drop off and so do the cost structure out in the industry.

Of course, over the past year, we've experienced kind of the reverse, right? We've seen rapidly rising commodity prices, and we've seen service costs going up along with them. We would fully expect the reverse to happen. But that's not what the future shift is showing us. Obviously, it's something much bigger than that, but we've seen so much extreme volatility that we need to be prudent and make sure that we can handle all of it, whatever we get thrown, and we feel very confident that we can.

[Operator]

[Operator Instructions] And I am showing no further questions. I would now like to turn the call back over to Darren Gee for closing remarks.

[Darren Gee, executive]

Actually, Justin, we'll take a quick moment here. We had a couple of questions just come in over the wire. I did want to address a couple of things. One was with respect to the acquisition.

And so, Dave, maybe I can hit you up just to comment a little bit on this acquisition we did in Q3. As we noted, we bought some lands and a little bit of production. Can you maybe talk a little bit more about the evolution of this acquisition and what opportunities we really see there, long term?

[David Thomas, executive]

Sure, Darren. As mentioned in the press release, we spent $26 million to purchase 49 gross or 42 sections of the land in the Brazeau area. I think there's 3 main takeaways regarding the deal. The first is that the lands have really good upside. It's top-tier upside in several of the key zones we target. We mapped 40 upside locations so far with 18 of these being Notikewin and most of the remainder being Wilrich, Falher, plus a few Cardiums. The Notikewins in particular, as we saw up in Cecilia, in that acquisition last year, they have the capability to be quite high impact wells. On this new Brazeau acquisition, we've already drilled and completed and tied in the first 2 Notikewins, and they've come close to filling up the spare 30 million of processing capacity in our new Aurora gas plant. And we're currently drilling a pair of Wilrich horizontals. And after that, we'll move to drill 5 additional freshly licensed Notikewins. The acquisition will play a significant role in the 2023 CapEx program.

The second takeaway is that the new acquisition really nicely complements the corporate one we did earlier in the year. And that example was sort of already talked about, it's the Aurora gas plant. It came with a lot of excess spare capacity from the earlier acquisition. And the land base will fill this up nicely.

But the third takeaway sort of linked to that is not so obvious until you look at a map of the land and the pipelines in the area. The new lands really fill in a significant gap between our Chambers and Brazeau gas plants. Now we have a continuous swath of almost 100% Peyto land that stretches for 30 miles. And the new pipelines that come with this deal, along with the pipelines that came with the earlier acquisition, plus our 3 gas plants, Brazeau, Chambers and Aurora, combine to give us quite a dominating infrastructure position here. And that should really help us to give us an edge as we continue to look for new opportunities to grow here. All in all, it's a big win I think for us, and thanks to all the people who participated in in making this happen.

[Darren Gee, executive]

Okay. Great. Justin, I see there is a hand raised. Is there a question from one of the listeners?

[Operator]

Yes, sir. And our next question comes from Michael Beall from Davenport.

[Michael Beall, analyst]

In regards to the distribution increase, a lot of E&P companies have a base plus a variable, maybe not as many in Canada as the U.S. As a shareholder, should we think about this new rate being a base that we hope to not reduce for a long time? Or is this sort of looking a year forward and in essence, a variable dividend?

[Darren Gee, executive]

Yes, it's a good question. Mike, we work in a volatile commodity industry, so sometimes I have to laugh when people talk about base dividends in oil and gas. Just because we've seen the commodity price actually go to zero. Nobody's dividend is a base dividend when you have no commodity price, and everybody ends up cutting those. But the reality is, we have good visibility into our business. We operate 99% of our production, all of our capital that we invest every year is in our gown control. We have a very good handle on how our business is expected to perform. And quite frankly, how our capital program is expected to perform. The one variable being the commodity price. And partly why we do as much hedging as we do to try and take that commodity prices variable out of the equation as much as we can. When our Board decides on a dividend level, it's with all that information in mind.

Obviously, we don't want to be reducing our dividend. We expect fully that as we go out into time, all of the activities that we have planned and with the future strip, we're going to be able to continue to increase it over time. But that obviously is subject to the future. And as we hedge and continue to move along, locking down those commodity prices and taking some of that risk off the table, we get higher and higher confidence in what we're able to deliver. We have a few levers, obviously, that we're playing with. With all this cash flow that we're generating, we've got a capital program, we've got debt that we want to take down, and we've got our dividend. And we're cognizant of the profits that the business is throwing off and the ability that we have to reward our investors with those profits.

It's a sort of a long answer, winded answer. I think we don't have to be as, I don't know, noncommittal with the dividend I guess. That's maybe not the right word to say, using both a base and variable piece because we have a lot of volatility that we can't attribute. We have I guess higher confidence in the business. We've never really considered a variable component of dividend. We've just done our best to be able to set the dividend at what we believe to be an achievable level.

[Michael Beall, analyst]

You didn't buy it in stock, and we're not saying that's the right or wrong thing to do. But looking at the long-term present value of your reserves, your drill inventory, you didn't mention that as being one way to return capital. What's the thought on that?

[Darren Gee, executive]

Yes, we don't. We haven't ever done, exercised a share buyback. Our thought is you're paying us to drill wells and to generate profit off of that investment. And that profit we can return back to you in the form of a dividend, and you can then buy the stock. Arguably, I'm probably a terrible stock picker and probably not the person to consult as to when to buy stocks and sell stocks. But hopefully, we're pretty darn good at drilling wells and making money at that. And really, that's what you're paying us to do, so that's what we focus on.

[Michael Beall, analyst]

Last question. As it relates to your drill inventory, roughly how many years do you say are drill, and I know a lot of variables go into it, but how many years' worth of drill inventory do we have, especially in light of these recent purchases? Just a range or round number?

[Darren Gee, executive]

Yes. We highlight that in our presentation as well. I think we're carrying about 1,300 locations or probably will be more by the time we rack it all up at the end of this year on our reserve books. That's really limited just to a handful of years out into the future where we're scheduling those wells. We believe we've got much more inventory beyond that, at least double that amount, so that puts it up over 2,000, maybe 2,500 locations on the lands we have today. We're drilling less than 100 wells a year, so that's a lot of years of drilling inventory into the future.

That said, we don't just sit back and harvest that opportunity. We're constantly looking for new stuff to do as well that is even better than what we currently have. If we can continue to every year add and increase the quality of the inventory that we have with new ideas and new locations, then we're never going to catch up to all that inventory. I know over our history as a sort of an example and a look back, we've typically added 2 locations, drilling inventory locations for every location we've drilled. And when you're adding at twice the rate that you're harvesting it, you're never going to catch up to all of that inventory. As long as we can continue to do that, we're doing our job. We've always got some really good quality stuff to be developing.

[Operator]

And I'm showing no further questions. I would now like to turn the call back over to Darren Gee for further remarks.

[Darren Gee, executive]

Thanks, Justin. We had one other question that came in overnight. And this isn't something we necessarily highlighted in the press release, but it was in the financials and MD&A, and that is with respect to this new credit facility. And the question was that we lowered our bank line from $950 million to $800 million.

Kathy, do you want to comment on why we did that? Or do you want Tavis to comment on that?

[Kathy Turgeon, executive]

Tavis can comment.

[Tavis Carlson;VP, Finance, executive]

Yes, sure. Good morning, everyone. Last month we extended our credit facility to October 2025 from October 2023. We chose to reduce the credit limit from $950 million to $800 million as we don't see a need for the high credit facility going forward, given our forecasted growth and free funds flow and forecasted debt reduction. The reduced credit limit benefits Peyto through lower credit facility renewal fees and lower standby charges on that undrawn balance. The renewal also allowed us to improve our credit price grid. Our prior credit facility was fine when our debt-to-EBITDA was much higher at 2.48. At the end of September, we were down to 1.16, which allowed us to negotiate that lower pricing grade. And that's going to help us offset that increase in Bank of Canada rate increases.

[Darren Gee, executive]

Great. Thanks, Tavis. Last question here that came in was just one about our extended reach horizontal program. We've talked at length over the last few years about how we've pushed longer and longer laterals.

Maybe Riley, you could maybe make some comments on just that program, how it's evolving? Do we have a bunch more technology to play with? Are we reaching the limits of the length of lateral? How has that driven enhanced returns for the wells?

[Riley Frame;VP, Engineering, executive]

Yes. We are continuing to see good success applying extended reach horizontals across many areas and many different species. And of course, the efficiency gains we see amortizing the sort of fixed cost portion of the wells across more laterals is really helping to drive better economic returns and it's helping to combat some of the inflationary pressure we see also. We predominantly apply this to the Wilrich, but obviously applied it elsewhere, as you alluded to, Darren, there. We've recently drilled some Dunvegan wells in this sort of fashion, longer wells, and those are generating some really good results. We've also applied this to some Falher channels where we're seeing some really good results and where we haven't really developed these channels before. The benefit of this is obviously the economic gains that we get, but it's also the inventory that comes from it.

As far as sort of like where we're pushing this to, I think given the system we're using, ball drop, we are kind of coming up against some limitations with it, but we've also seen those limitations continually push out and out into the future here. Where if you go back a couple of years, we were seeing limitations in sort of like the mid-30 stages and now we're able to push it to 50. As time goes on here, we're continuing to drive wells longer and apply the new technology as they come available. Yes, this has been pretty critical for us as far as developing a lot of our plays, and it's really critical for us as far as the new stuff we're doing in White Horse as well, which is really great. We'll continue to push as hard as we can to go as far as we can and to try to maximize the economic benefit we get from it.

[Darren Gee, executive]

Okay. Good stuff. It doesn't look like there's any additional questions, Justin, so maybe we'll wrap it up from here. We're excited, obviously, with what we've got on the lineup period for the rest of Q4 to get us to the end of the year. And of course, it doesn't stop there. We usually do shut down for a little bit of a Christmas break with the drilling rigs and give the guys a few days off, mostly from a safety perspective more than anything. But everybody has been working hard, our rigs have been running pretty steady all year long, so it's good to give the guys a little bit of a break, and then we'll get back at it in the new year.

We've got a lot to do next year. It's going to be an exciting year. And then by the end of the year, we should be selling gas to a brand-new power station right next to us, so we're excited to see that, too. I think we're set up really well, and we're going to be reporting obviously along the way as we go. Actually, JP will be the one reporting to you every quarter, so please listen in, and we'll be back to you with the reserves I guess in February and then the Q4 results shortly after that. Thanks for listening in to the call this morning.

[Operator]

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