Peyto Exploration & Development Corp
TSX:PEY
Earnings Call Analysis
Q3-2023 Analysis
Peyto Exploration & Development Corp
As we start the narrative, we're presented with an executive affirming that royalty rates are projected to remain consistent with the previous year's levels for the company, laying within the 8% to 10% range. As AECO prices potentially rise, the rates could tilt towards the higher end of that spectrum. An insight into the company's tax scenario reveals that cash taxes are expected to climb from the current year, with estimates putting them around 12% to 14% for the next year. The increment is partially due to the Repsol acquisition, which does not bring significant tax benefits with it, suggesting careful navigation ahead for the company on the fiscal front.
The spotlight turns to operating costs, which are set for an upward trend owing to decreased plant utilization. However, the executive sees a silver lining, with substantial opportunities for cost improvements on the horizon. The goal is to nudge operating costs downward throughout 2024, despite an initial increase.
In the fiscal blueprint for the company, a balanced capital program is articulated, with a possibility of escalating investment towards year-end. Production, conversely, is expected to be stronger in the latter half of the year, following a relatively flat performance initially. There's an average production target of around 132,000 BOEs per day, climbing to an anticipated exit range of 135,000 to 140,000 BOEs per day for 2024. The company hints at flexibility in the execution of these plans, subject to market conditions and cost considerations.
The discussion ventures into mergers and acquisitions, with the company examining its assets for potential noncore elements that might be divested. The executives appear confident in their recent acquisition and suggest selective trimming, if required. Moreover, infrastructure optimization and redirecting gas to more efficient plants are on the table, with an overarching aim to enhance netbacks and liquid recovery rates.
Addressing the Repsol acquisition, the company clarifies that past capital spend by Repsol has been predominantly in line maintenance, leaving the facilities in good condition. Looking ahead, the focus shifts towards preventative maintenance, with a significant 10-year turnaround project at one of Repsol's large facilities, indicating the proactive approach to asset management adopted by the company.
As the conference draws to a close, optimism pervades the executive's tone, signaling enthusiasm for the integration and growth following the Repsol acquisition. The company acknowledges the need for some time to thoroughly assimilate the newly acquired assets but looks forward to the journey with eager anticipation.
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Thank you for standing by, and welcome to Peyto's Third Quarter 2023 Financial Results Conference Call. [Operator Instructions] I would now like to hand the call over to President and CEO, JP Lachance. Please go ahead.
Thanks, Latif. Good morning, folks, and thanks for joining Peyto's third quarter 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.
Present with me today in the room, we have 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.
Before we discuss the quarter, on behalf of the management team, I'd like to acknowledge and thank the Peyto team as we always do for their efforts over the past quarter, including our people in the field for their commitment to Peyto. And I mean that sincerely as a lot of people are working extra hard these days to integrate the recently acquired Repsol assets.
And it was a very busy quarter at Peyto, not so much on our capital program, which was relatively quiet as we continued with our careful approach to spending, given commodity prices were still down significantly as compared to last summer. I think AECO monthly 7A price averaged only $2.26 a gigajoule, and NYMEX was around $2.58 MMBtu for the quarter. But our systematic hedging and our diversification portfolio helped us maintain cash flow while our capital program kept us flat on production over Q2. Cash cost of $1.05 per Mcfe, excluding royalties, were up slightly from Q2, but when you factor out the $0.05 per Mcfe we paid for some partial financing fees incurred from the acquisition, they were actually slightly lower, reflecting typical lower summer operating costs, but also that we've seen inflation effects moderate now.
Obviously, we're -- we've been very busy doing some exciting things over the -- other than the drilling program we -- over this last quarter, like another tuck-in deal. And I call the Repsol deal that because it really fits with our strategy to acquire assets, really adjacent to our own operations that come with lots of upside and operated facilities. So on October 17, we closed the Repsol acquisition. And when you consider the bids went in shortly after our last call in August, that was pretty fast. But because it closed in Q4, there's no production or revenue contribution from this deal in our Q3 results aside from that initial financing costs.
Clearly, we're really excited about the opportunities here. We see over 800 high-quality drilling locations right now, but I expect once we get drilling, we'll spot even more like we usually do. For us, it's like going into a time warp since many of the great opportunities we pursued in the past in our own lands are right next door -- right next door to these are now available again on Repsol assets.
The difference is that this time, we get to use our latest drilling techniques that we've been refining over the years like our extended reach horizontals and increases in stimulation intensity. So that means the wells should be that much better. And as I said in the monthly report just published, the real work begins now, and we've already begun drilling.
Lee has 2 rigs running on the Repsol lands, and we expect to drill 7 more wells by the end of the year, 7 wells in total by the end of the year. That, coupled with our 2 rigs will help drive exit production to somewhere between 126,000 and 128,000 BOEs a day depending on hookup timing. And while much of our staff is busy integrating data with systems into Peyto, our operations team is also busy working up field optimization projects, which I'll get Todd to expand upon later.
The field synergies with Peyto's greater Sundance area are fantastic. I would encourage you to look at the slides in our corporate presentation and you can see the overlay of the plants and the gathering systems. That picture says it all. [ Beyond control ], we operate 1.5 Bcf a day or 1.4 net Bcf of processing capacity in the Deep Basin.
We're also -- we also released our preliminary budget for 2024, which targets between $450 million -- $450 million to $500 million capital spending, which should grow us to around 135 to 140 BOEs a day by the end of the year next year. And that plan has a combination of activity on both the newly acquired Repsol assets and our own Peyto legacy lands where we plan to drill around or between a total of 75 to 80 net horizontals. On top of that, we expect to spend about $10 million on closure activities to stay ahead of our abandonment and reclamation obligations. We believe our plan to grow over the next 2 years is well timed with the expansion of LNG takeaway capacity, both from LNG Canada, which is getting built and the projects in the U.S.
In the meantime, we expect gas prices to remain volatile, so we've protected our revenues with a robust hedging program. 68% of our forecasted gas volumes are fixed for 2024, and 56% for 2025 at prices around $4 an Mcf, which is quite a bit higher than the strip for 2024. We calculate that not only can we support the dividend and the capital program that we've got contemplated in our plans but also pay down debt, such that we should be under 1x debt-to-EBITDA, trailing EBITDA sometime in 2025 under the cred strip.
But beyond our hedges, our remaining exposure for the winter -- for this winter and into 2024 is some premium gas markets like Dawn, Malin and California and the U.S. Midwest. And of course, we also have our supply contract to the Cascade power plant for 60,000 GJs a day, which has been delayed slightly, but should be up and running in Q1 of 2024, and we're all connected and ready to go in there when they are.
We also released our annual sustainability report as part of the Q3 release, and you can find that on our website. We continue to hold a view that our focus on operational excellence naturally keeps our cost down, but also serves to emit less methane, use less water, use smaller surface footprints and keeps facility utilization as high as possible. This report covers the year ending in 2022. So it doesn't include the newly acquired Repsol assets. And of course, next year, we'll reevaluate the targets based on these combined assets.
Before I close my opening remarks here, I'd like to congratulate Riley on his promotion to COO and Tavis to his promotion to CFO, that will take place early next year. I know you guys are excited as I am to begin the next chapter at Peyto. And thank you, Kathy, for 20 years of dedication to Peyto. She moved forward to a retirement in 2024.
But before we go to the phones, Latif, I think I'll let Todd maybe expand upon a little bit. If you could -- Todd, if you could expand on these operational -- these operations optimization projects as they relate to the Repsol synergies that we've been discussing. Maybe you could provide a little more color as what your team has planned for the rest of this year and into 2024.
So Todd, I'll ask you to maybe expand on that first before we turn it over to calls.
Sure, sure. So I guess maybe to expand a little bit on your recognition of the Peyto people, I would say that we're pretty happy to see the Repsol people that we -- former Repsol people that we brought in really working hard along with our Peyto people to identify some synergies and optimization opportunities. They really stepped up since they came in and they look like really great additions. So we're pretty happy on that. I'm sure that's probably other groups are seeing that too, I hope.
As far as what we've got planned for the remainder of this year, we've got some kind of quick wins, if you want to call it that. We've got immediate plans for three projects in the Greater Sundance area, two should be completed here in November, one in December. Two of them involved some pipeline tie-ins that will redirect roughly 20 million cubic feet a day of well gas into lower line pressure and higher liquid recovery plants.
And then a third involves a compressor sales pipeline redirection that ends up removing the need for about a $2.5 million pipeline that we were previously envisioning building. So we have that savings. And then all that gas that moves into that system will end up being at a lower line pressure, so that will help. And we're doing it for minimal cost, a few hundred thousand dollars and very little regulatory applications required.
And then as far as going into 2024, we're going to focus on really adding infrastructure, I guess, and connecting infrastructure so that we're able to connect Repsol plants into Peyto infrastructure so that we've got swing capability so that we can move gas around from plant to plant in outages, and then it'll continue to look for lower line pressure opportunities and that sort of stuff.
So we've sort of got about 5 projects that we're envisioning right now. Several of them will be up in the northern area, sort of Wild River, Wildhay, Cecilia, and that will connect those 3 plants together and then further south connecting the Edson gas plant, the Medlodge gas plant into the Oldman, Swanson and Nosehill facility. So we're excited about that. And expect to have a lot of this stuff done probably in the first half of 2024, and then we'll continue working on some of the little bit more nuanced things as we move through the first half of the year. And we'll probably be able to do -- we're expecting costs -- pretty minimal costs even for some of those larger header modifications and small pipeline builds to make that happen.
Okay. Thanks, Todd. That's good better color. Okay. I imagine there's a lot of questions. So Latif, let's open up the phone lines there. Perhaps we can see what we have for questions.
[Operator Instructions] Our first question comes from the line of Jeremy McCrea of Raymond James.
It's been a month since closing here now. And I'm curious if you're getting any kind of update just in terms of some of the synergies that we could have expected. Are you getting maybe -- I'm just trying to think of like better potential for more access into the California market, better rig contracts, better anything just with some of the synergies and contracts that you guys may have had with Repsol.
And then second question, a lot of M&A going on here in the sector here right now. Are you guys done with these tuck-in actions? Or is there more still to come here?
Okay. So Jeremy, thanks for your question. On the first, I think Todd alluded to some of the projects that we've got working on as far as optimizations go. We did get a little bit of diversification with the acquisition into a little bit more California, into the California market with the marketing side.
As far as far as synergies around drilling and et cetera, really, we haven't changed our program, all we do is redirect it more on the Repsol assets. So we still have 4 rigs running. So that hasn't really materialized any changes to sort of -- or larger synergies related to contracts like that.
With respect to -- what was the second part of your question?
Just a lot of M&A going on in the second year right now. Just your comments on that and how do you guys fit in with all this M&A that you -- are you guys done? Or are you still looking at things or are still opportunistic?
Yes, we haven't changed our approach. And in fact, I'd argue that what we just did isn't any different than what we've been doing all the way along. We call these tuck-ins because they have the synergies. When they're right next to our own assets, we understand them really well. And so we'll continue to do that.
For us, it's -- the strategy really hasn't changed. We'll look at opportunities as they come around, and we'll jump on them if we think they make sense to us and we can make them work. And typically, they're going to come with facilities and they're going to come with a lot of opportunities so that we can continue our strategy of owning, controlling. We think that's really important. And we'll continue to look at any kind of opportunities like that.
I think the Repsol opportunities -- or the Repsol acquisition provides us with additional opportunities, as we move out, our footprint gets bigger, and we see more opportunities on other kinds of tuck-ins that we'll pursue as we go along here. But besides that, I mean really, we have -- we're also not -- we're looking at landfill, we're looking at other ways to add to our land base.
Maybe you want to comment on that, Derick?
Yes, sure. Yes. We're definitely active still on the landfill front, continue to target prospective lands that fit our profile. In the quarter, we did pick up 10 sections of prospective lands for an average of 211 an acre, and that put us to a total of 26 sections year-to-date for an average of 178 an acre.
So we're active on the land front too, which is good...
Yes. So yes, with the additional footprint of the Repsol lands, many new landfills in the future will now fit our profile given the closer proximity to our pro forma land base. So we'll look to capitalize on those opportunities once they arise.
[Operator Instructions] Our next question comes from the line of Chris Thompson of CIBC.
Just firstly, on some of that infrastructure work that you're doing. You mentioned redirecting 20 million a day with these projects coming up here at the end of this year. Does that actually increase utilization on a specific plant? Does it decrease utilization on another? How should we be thinking about that? I noticed you specifically called out utilization in the press release there.
Yes, we'll get Todd to sort of let's expand a little further on that. I think in general, though, we're looking at this from the perspective of we've got to get drilling here and start growing production in those areas, and that will really be the key driver for OpEx reduction. Because obviously, fixed cost at the -- they have been underdeveloped, and so the fact that these plants have not been -- their production has been falling, the fixed costs are spread out so it [indiscernible] costs. And so that utilization is down relative to where we'd like to see it. So obviously, we're going to get drilling here.
But in the short term, we talked about these projects' plan to move production around and to optimize it and part of that is we're lowering line pressures to help increase throughput as well, right? So utilization rates are going to move around as we do that, obviously, right?
I think on -- specifically on the 20 million cubic feet a day of gas that I mentioned, that is moving some gas that's up in the Cecilia area. That Cecilia plant has been full for quite a long time. And its liquid recoveries are lower than any of the other plants. So our plan is to [ make ] the connection right there, Repsol pipe going right past Peyto pipe, and we're going to move some gas up further north into the Wild River plant.
The left line utilization is already 100% as it were, but now we're going to help lower pressures and increase utilization.
Exactly. And we have -- it will move a little bit of gas maybe out of the Wildhay plant, but it will relieve the infrastructure that we were directing to move that gas around. So yes, definitely will help online pressure and positively affect a lot of other wells in that area.
Got it. Okay. And then from an infrastructure spending standpoint next year, you mentioned the big turnaround at the Edson plant. So just wondering if you can expand a bit on what the estimated costs are for that and other infrastructure spend in the budget.
I won't give specific projects because those will move around on us, Chris. But generally speaking, our facility budget is close 15% to 18% of our annual budget, and that isn't any different than in the past. Maybe I guess, the past year, it was a little lower than that. But -- so there's a few projects that we've got on the go this year related to that, the gas plant. The Edson gas plant turnaround is actually spaced over a couple of different months, so it's spread out. But it will be around -- the infrastructure costs, facility costs will be in that 15% to 18% of our capital budget range.
Okay. And then next question for me. How should we be thinking about your royalty rate next year and then cash taxes as well? And we've talked about operating costs in the past, but just wondering if there's been any change to your outlook on OpEx as well.
Sure. Maybe we'll get Tavis to answer the royalty question here first, and we'll talk -- we'll talk about some other ones. Go ahead.
Yes, Chris, I think our royalty rate is going to be consistent with where Peyto has been over the last year. Like obviously, your AECO does pick up a bit. We could see a little bit higher, but somewhere around that 8% to 10% would be a good place to be modeling it now.
In terms of cash action, we're modeling around 12% to 14% next year, it's going to be a bit higher than where we're at in 2023. The Repsol acquisition is a partnership, so it doesn't come with many tax pools. The resource pools and noncapital losses will flow off to the partners in Chile. So really, we're only inheriting a little bit of UCP pools and some resource pools that we would have generated from June 1 during the effective period, I guess...
Chris, you also asked about operating costs. Operating costs, I mentioned it earlier that the utilization of their plants is down, and we'd like to think we can -- we have significant improvements that we can make on operating costs. Step-off costs will be higher.
But we've already -- we're already going to see some changes to that. In fact, as far as our people, synergies are out field. And so costs are going to go up for sure, but we still think that we have lots of opportunities to move closer to the downward direction over the coming year in 2024, and that's what we're focused on doing. If you look to our corporate presentation, I have sort of a total cash cost slide there that gives you some direction around where we see our total cash cost, excluding royalties in [indiscernible] in the corporate presentation to help you with the numbers.
All right. Maybe just last question from me. Just with your preliminary budget and guidance out, could you maybe help us a bit on the shape of the capital profile next year and the shape of your production profile next year?
Yes, sure. So the capital program is probably relatively balanced throughout the year, would be a little bit higher in the back end. And because we got a different -- and a lot of that's to do with the timing of facility projects that don't necessarily affect production. Production typically will be back-end loaded for us.
We have a couple of things there. We come out of the year, so we had a little bit higher declines in the front end. And so we're relatively flattish in the first half of the year and then we grow in the back half, which is very typical of sales profile.
And part of that is to do with the fact that we have the breakup period. We're modeling right now that we are going to be running all 4 rigs through breakup. That could change. So that capital profile could change as well if we decide that it's a good time to go and it makes sense, market's there, we can get to lower costs, which we've typically done, but not always. So right now, we're modeling out, more or less, a flat front end and then a higher back-end production side, and capital is more or less balanced throughout the year.
Okay. I think you mentioned exiting 2024 between 135,000 and 140,000 BOEs a day. So I mean, if we just connect the exit-this-year guidance to the exit-next-year guidance in the straight line, we kind of get to about 132,000 a day as an average next year. Is that the right way to be thinking about it?
Yes. Again, I would say, come out of the year, stay flat, first half. And then ramp it up in the back half to those exit volumes. That should get you there.
[Operator Instructions] As there are no questions in queue, I would now like to turn the conference back to JP Lachance for closing remarks -- actually, sorry, we do have a question. I'm sorry. We have a question from the line of Travis Wood of NBS.
Two questions. First, just kind of carrying on from Jeremy's question around M&A. Anything that you see within the portfolio kind of pro forma now that you've been operating it for a month that you could carve out as quotation noncore, including potentially some facilities with that?
Yes. There's -- obviously, we're going to continue to look at these assets in a way that we've always been focused. And so -- but really, what we purchased here is quite focused, right? So none of the -- I would suggest that the Repsol assets themselves are something like that we would consider carving out necessarily. It's really, really nice, that's why we bought it.
But there may be some minor properties that can't allow this, that we would love to [ discuss ] for sure. And we'll continue to look at that depending on what opportunities are out there and how we want to sort of direct our capital program. But nothing specific.
Okay. And then unrelated, a lot of comments around maintenance and kind of optimizing infrastructure and directing volumes kind of zig zagging across the portfolio. Anything from an optimization standpoint as we think about liquids capture? Is there anything within that optimization outside of costs? Is there anything on the revenue side where we could expect higher NGL ratios on the back end?
I think Todd mentioned there that with respect to redirecting some of our gas to higher efficiency, higher liquid recovery plants, certainly is part of that, and that's part of the -- it's about making money, it's not just about production, right? So obviously, the higher liquid recoveries were they sense, but they got to make sense, right?
If the deep cut doesn't make sense, we turn it down -- we turn it off, like we always have with Oldman and the same would go with anything on the Repsol lands. We would handle it the same way. So we will always be looking for the highest net back we can get. If that means changing our processes or moving production around to do that, we're going to be doing that.
So -- and I think this gives us even more opportunity now that we have this interconnection. As Todd mentioned, we're going to interconnect all these plants together to give us maximum flexibility to be able to do those kinds of things. But nothing specific to tell you right now, Travis. We're still in the throes of all this, right?
Okay. Fair enough. And then just specifically for Edson and the maintenance there. Is that -- is it related to just kind of not enough capital spend from Repsol over the years? Or is there something specific that you want to target before you start to change throughput there?
Yes. First of all, actually, I would say the capital spending done by Repsol in the past has actually been to maintain -- the gas line has been great. I mean that's what they have spent their money on. So the condition of that facility is in great shape. It's just -- it's coming up to its turnaround. And we talked -- to expand upon that, the money we're spending there is more on preventative maintenance as part of an ongoing program as opposed to fixing it up...
Yes. This is their 10-year turnaround. So they've got -- it's obviously a very big facility. So there's a lot of vessel entries that have to happen. A lot of [ PFEs ], changes, that sort of stuff. And then along with that, some R&R work to replace stuff that's maybe coming to end of life, which is just typical. You do a 10-year and 5-year schedule, so it's just timed out that we picked up the assets for a time, for a very large 10-year turnaround.
[Operator Instructions] And I show no questions. Mr. Lachance, the floor is yours for remarks, sir.
Okay. Thanks. Well, thank you all for tuning in. As we -- we're excited about going forward here, and we need some time to digest. And similarly as it were, the assets and going forward, we're quite excited about the Repsol acquisition and probably can get that from my tone. So thank you very much for tuning in, and we'll see you next year.
This concludes today's conference call. Thank you for participating. You may now disconnect.