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

Good day, and thank you for standing by. Welcome to the Peyto's Year-end 2023 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, President and CEO, JP Lachance. Please go ahead.

Thanks, Daniel. Good morning, folks, and thanks for joining Peyto's 2023 Year-end 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 and issued -- that was issued yesterday. In the room with me to answer any questions, we have Kathy Turgeon, our Chief Financial Officer, at least until the end of the month; Riley Frame, our VP of Engineering and Chief Operating Officer; Tavis Carlson, our VP of Finance, soon-to-be CFO; Todd Burdick, our VP of Production; Derick Czember, our VP Land and Business Development; and last but certainly not least, Lee Curran, our VP of Drilling and Completions. Before we discuss the quarter and the year on behalf of the management group, I'd like to thank the Peyto team for their contributions to a strong quarter, a strong year and their efforts towards integration of our new assets. 2023 was an eventful year for Peyto. We had a few changes. The change can be good. We closed a meaningful acquisition in the fourth quarter. We refreshed the senior management team as part of our [ only ] succession plan, and we turned 25 years old. One thing that doesn't change is the team's commitment to the profitable growth of Peyto's assets using the approach that's made us so successful over the last 25 years. And of course, I'm talking about our focus on being good stewards of shareholder capital by keeping our cost down owning and controlling our infrastructure, securing our revenues through hedging and diversification and returning profits back to shareholders. Okay. The big event last quarter and last year was the acquisition of the Repsol assets. I'll forgo the nitty-gritty details of the deal because by now, you've heard it all the -- the multitude of all the locations we essentially didn't have to pay for the synergies with the infrastructure in the field and the fact that we know these lands like the back of our hand. The important thing is now that we've been able to operate them for a little while, they are what we thought they were. We're basically what we expected. We're getting some fantastic results with our drilling program, and there are numerous opportunities to optimize and drive down costs in the field. And maybe I'll get Todd to elaborate a little later with some details on the projects that his team has been working on over the last few months. But certainly, operating cost reduction will be a focus for Peyto in 2024. Although the acquisitions and the metrics of the deal are great, it's not to be all done by a very effective drilling program that was executed by the team last year. We spent less than the low end of our guidance, and we delivered reserves. PDP finding cost of $1.15 per Mcfe, or if you include the acquisition, PDP FD&A was a total of $1.21 per Mcf, and I believe that's best in class amongst our peers. With the help of our disciplined hedging program and our diversification, we managed to mitigate the impacts on funds from operations despite the significant drop in average daily AECO and NYMEX prices by 50% and 60%, respectively, from 2022 levels. In fact, 2023 was the third highest year of funds from operations per share in the company's history. And even without our hedging program, it's the same third best year we've had and it sort of points to the underlying qualities of the business. One of the qualities -- one of those qualities is our force is our industry-leading field costs, which helped us to build a solid $3.51 per Mcf field netback. And when you combine that with our FD&A, it yielded us 2.9x PDP recycle ratio for the year. And I think that competes too with best-in-class. So we did have a little noise in the quarter with our cash costs. Operating costs are up as we expected with the new facilities and interest costs are also up as we took on some incremental debt to get the deal done last October. There were some onetime costs relating to acquisition financing and integration that translated into about $0.09 per Mcfe and that we don't expect to carry forward. Looking forward, with gas prices where they are, we're acting prudently with our capital plan for 2024. We are targeting the low end of our capital guidance closer to $450 million for now and we'll watch prices closely and adjust our spending accordingly. Similar to last year, we expect to slow down in Q1 during breakup and then ramp back up when we have greater confidence in the forward strip. The degree that we slow down or bring on production will depend, of course, on the cooperation of the spring and summer weather. But the rains come, which, of course of where it needs right now, it will slow us down. And there is a real concern around drought conditions in Alberta. If you read the recent fatal monthly report, you know we don't typically use water from surface sources. We drill water wells for our development program. And we use a lot of that water than most because of the quality of our reservoirs, and of course, we have a full back recycling program that we try to implement as well. So we don't believe drought conditions will affect our drilling program at this point in time. We have a major turnaround plan for the Edson plant. It's a 1 in 10-year turnaround. It's broken up into 2 parts. One is in April and the balance is in September. Those costs are included in our budget, and we expect there will be minimal production impacts over those quarters. But of course, until we get under the hood, we'll never really know. Longer-term, we still have -- we're still very optimistic about natural gas prices that we believe the start-up of LNG Canada and build out of LNG egress in the U.S. over the next couple of years is constructive to the commodity and that demand for natural gas isn't going anywhere anytime soon. In fact, with all the coal-fired plants that are still being built around the world, there's a great opportunity to displace those with -- those plants with cleaner-burning LNG in the future. But in the meantime, our diversification and hedging program has our revenues well protected in 2024. Approximately 70% of our forecasted volumes are hedged. And even in 2025, where we have about 56% of our forecast gas volumes fixed, the gas, coal prices, so that gives us the confidence to execute our capital program, pay our dividend and pay down some debt for the balance of the year. One of those diversification markets is the 60,000 GJs a day or 52 million cubic feet a day of gas supply agreement that we have to the Cascade power plant. We're ready and keen to start delivering gas to that plant, but that won't begin until they are fully operational. They did have some start-up problems and they are continuing to work through the commissioning stages, and we expect to be providing them with gas sometime during the second quarter. So that kind of wraps it up. But before I go to some questions from the phone or from overnight from the from e-mails, Todd, maybe get you to provide an update on your team's latest plans on optimization and cost reduction projects that you guys have achieved so far this year and plan to do for the remainder of the year.

Sure, JP. Been a very busy 4.5 months. Prior to closing, we have prepared some initial plans and ideas. And obviously, it took a few weeks to get familiar with the assets. The new employees, the new staff and determine where to focus our initial efforts. Now regarding that staff, we kept about 2/3 of the field operations people and about half of the total field people. And for many of those folks that we retained, it was a bit of a shock and we needed to give them confidence that things would run fine with less people because essentially, our processes in the field are quite a bit more efficient than the way that the Repsol framework kind of runs. So it was imperative that we introduced the Peyto culture and explain the company's hands on and accountability philosophies. And as we sit here today, I can comfortably say that a large majority of those folks have embraced this philosophy and what Peyto gets out of that is production focused and cost-conscious individuals operating the company's assets. And ironically, I guess, a long stretch of minus 40-degree weather really helps to bring a team together. So as we went through that initial period, we were also working on integration and optimization initiatives and started to identify specific projects. In many ways, that we felt like kids in a candy store that was so much out there that we wanted to do, could do and hope we could do. So -- but initially well optimization began immediately following after acquisition. We started seeing gains in the first month. For the most part, things we're in really good shape as far as the assets we acquired. But there were still some things that Peyto does that we were able to introduce and those efforts, especially downhole equipment work, is continuing today. We've been working hard on improving plant reliability and run time. The press release it mentioned us looking at several initiatives to improve reliability following a cold snap in January and the initiatives we're looking at and applying not only applying cold weather but year-round operations. Prior to the acquisition, we were operating 11 gas plants at a run time of 99%. So we're taking that expertise and applying it to the 4 operating plants that we purchased, and we're seeing [indiscernible] also are in reliability and reduced operating costs. With respect to operating costs, we were modeling slightly higher costs for Q4. So I'm cautiously optimistic that we're starting from a lower spot than we expected, maybe we were able to do more than we anticipated in those 3 months, but either way, it's encouraging here early on. We've also been busy connecting pipeline infrastructure. In many cases, these projects allow Peyto to process old and new production at underutilized gas plants. One of the things we're focusing on. And once we receive regulatory approval in December, we were able to tie 2 Repsol pipelines into Peyto pipelines in the Oldman area. This included diverting a compressor station from the Edson gas pipe into the much closer Oldman gas plant. And the second project effectively gave us some swing capability to move gas out of the Med Lodge plant into either Oldman or Swanson. Here moving into 2024. We've done 2 more infrastructure projects. In January, we completed a project did divert Gas from Cecilia over to Wild River that helped to offload the currently that capacity Cecilia plant and see a better liquid recovery on that diverted gas. And the second project is similar to the one I mentioned we did in December where we added some swing capability between Medlodge, Oldman and Swanson. We're currently waiting on regulatory approval to do a large header modification that will tie in large diameter infrastructure between Oldman, Swanson and the Edson gas plant. This is a precursor to a debottlenecking project we are planning later this year that will connect Swanson infrastructure. This again is to accommodate drill plans in the area, but again, it gives options to move gas in and out of plants as needed, especially during offsets and outages. And it also gives us more flexibility to reliably deliver gas to the Cascade power plant. And we're not done. So early in Q2, we plan to divert significant volumes out of [ costly ] third-party facilities in the Wild River area and send them down to Edson for processing. And then later in Q2, we will be reactivating a large compressor station in the Edson area to accommodate the drilling that's happening down there. Beyond that, we have 4 or 5 other projects that were either waiting on regulatory approval or internal scoping and cost estimating -- they may or may not come to fruition, but it's better to happen shovel ready as it were. And then we're always seems weekly coming up with new ideas of things we can do. We'll execute on those as sort of [ one team ] and our development program continues. But all in all, we're happy with where we're at. We know there's lots more to do. We're constantly working on that, and like I say, going up with new ideas.

Okay. Thanks, Todd. Wow, lots to unpack there. Thank you very much. Okay. We'll open it up to questions now, Daniel, please. I imagine there's a few.

[Operator Instructions] Our first question comes from Amir Arif with ATB Capital Markets.

I appreciate the color on the different projects you're doing on the operating cost front. Just curious, could you kind help us quantify what the impact could be over the year? I mean, I understand it's only been a few months. But thinking about a 5% or 10% improvement in unit OpEx over 1 year, 2 years?

Thanks, Amir. Yes, I think the way I would think about this, it's a bit early to tell exactly what we're going to see here. So we -- I'd like to get some history before we can give you a number. But I would point you to our slide in the corporate's presentation of taxable cash costs in aggregate and points to sort of what we -- how we see the business changing over the next 3 years, I think, in Slide 21 in the January presentation, there has a little bit of a color around our cash costs, excluding royalties and taxes. It gives you a sense of where -- how we feel the total in aggregate will be. So we, of course, expect some kind of reductions, 5% or 10%, not unreasonable, but I think we need to see some history here first to be fair, Amir.

Yes. Fair enough. I appreciate that color. Just -- and then a question on the hedging side. And just given that you're significantly larger gas producer now, historically, you focused mostly on financial contracts for your hedging. I was just curious with the larger size do you plan to include more physicals? Or do you plan to continue to focus on financials for the majority of your gas hedging and diversification?

Yes. Right now, Amir, we do have a little bit of both. As you know, we have some physical -- we have physical volumes that go to Emerson. And we do have some other -- some of our other contracts are in fact, physical relationships. And so it's not all just financial. So I think we'll continue that sort of mix as we go forward. You know that we like to do some, what we call, basis deals to get ourselves. That's what we call synthetic exposure to other markets, and we'll continue doing that. We are continuing to do that to allow us to access those other hubs and other places without having to make that long-term physical commitment. But we do have some already that are physical, right? Emerson being one of them.

Just in terms of the incremental gas volumes, is it those going to be most of financial? Or do you plan to keep a similar mix?

To the extent that we get good value for them, we'll consider them for sure, yes, physicals.

Okay. Sounds good. And then just a final question on the 8 wells that you had drilled on the Repsol lands. Better EURs on those wells than your historic stand-alone wells. Were those in a specific zone or is that a good cross-section of different zones that you'd be targeting on the Repsol lands in terms of the EUR per well that we saw on those wells?

Yes. Those are -- obviously, we had to get -- to drill those first few wells, these were wells that we would have had locations to where we could use our own surfaces or something that we have prepared. So -- but maybe I'll let Riley talk to the specifics around the species mix there.

Yes. So those wells were predominantly not [indiscernible] wells. There was also a couple of upper flare wells that were in there. So I wouldn't say it's a total cross-section of what we have out there. There's obviously a lot of Wilrich, Dunvegan and a lot of other plays. So yes, it's definitely is up but we are also seeing in the wells that we've drilled in the first half of this year. We've gotten into the Wilrich and some of the other plays, and we're seeing just as good results out of them as well. So I think overall here, sort of from last year into the first half of this year, the cross-section is pretty representative, and it's holding up sort of where we would expect is really high-caliber results. So...

I'd point you, Amir, to our February report, it gives a nice breakdown of what was drilled in those 8 wells in our February monthly report there.

Our next question comes from Michael Harvey with RBC Capital Markets.

So just a quick one on your horizontal well length. So it looks like your wells got quite longer in '23 just after years of being reasonably flat. Do you see that increasing further in 2024, just with the Repsol lands and what some of the other operators are doing? And then how do you kind of balance that longer horizontal well just with overall inventory numbers, which would, of course, come down a bit with longer wells.

I'll maybe get Riley to answer that question. I think generally speaking, we would have -- our location counts would include what we expect to drill for length, but maybe Riley on our reserve reporting, which you spoke about.

Yes. So I would expect that our horizontal length will continue to increase slightly here over the next couple of years. We're just -- the quantity of wells in our program that sort of qualify us extended or -- extended reach is going up. Obviously, with the addition of the Repsol lands, it kind of gave us obviously a reset. And so what we've been able to book on those lands is actually mostly call it, 1.5 miles and 2-mile wells. So yes, so over the next little while here, I would expect that number to keep creeping upwards. And then just as far as what was booked, it is reflective of how we're going to attack it. We went through a process a few years ago of trying to sort of correct our reserve books to sort how we were actually drilling wells. And so by virtue of how we book the Repsol assets and everything else this year, it is fairly reflective of the longer laterals in the reserves. So...

Our next question comes from Jerry McGahee an investor.

My first question pertains to the pre and post Repsol comparison of the value of our liquids. The -- before Repsol, the number seem to be 11%, 12% liquids, and now the number seems to be percentage-wise on a volume basis a little bit higher. My question is, if we -- rather than looking at it on a volume basis, we would look at it on an economic basis, as measured by the dollar value of the liquids. It's my impression that the dollar value of the liquids proportionally for the addition would have declined because the Repsol liquids are a different combination of there's more lower value components to the liquids, if that -- I don't know if I've said that right. But I'm just interested in if that is correct and how we should look at that in terms of the numbers like the ethane in the Repsol lands, for instance, is a lower value than the percentage condensate in the legacy Peyto production?

Yes. So Jerry, just to frame that a little bit, so we bought 23,000 barrels, of which 75% are gas and 25% were liquids. But as you point out, a fair bit of that, and it was in the original presentation is -- or not a fair bit, but some of it is about 2,000 barrels of the liquids is ethane. So from a value perspective, essentially gas value. And one of the things that Todd was referring to was moving some gas from the Wild River area down into Edson is, in fact, to change that up a little bit here. And we're going to -- rather than paying someone to remove ethane, which we really get not much more value, this would be a cost savings matter. In the second quarter, we plan to move the volumes that we normally would be sending over to that deep cut facility down through to Edson instead. So that will help increase our utilization at Edson and it will also lower our cost structure. So that will sort of write itself in time here as we remove less of the ethane from our gas stream. So minor impact on liquids volumes, but essentially, probably an increase, if you think about it, an increase in value to us, right?

Right. Okay. That's great. And just a couple of quick follow-ups. I noticed in the MD&A that the hedging that's been done since the end of the quarter on the gas side was pretty limited. 20,000 gigajoules for April 1, '26 to October '26. That would be slower than the normal pace that we've seen in the past. So I'm just curious if that's represents any change in the approach? Or if it's -- well, I'll let you answer that, sorry.

Yes. So no, we don't -- if you look at our past, we've sort of 3 years out, we would normally be hedging 3 years out, which we're doing and we're continuing to do. So we will -- we are still going to take '26 off the table. We'll continue to do that as we move forward and that's sort of mechanical way. We took a lot more off the table in '25 when we did the deal, and that was to help protect some revenues on the front end of the deal. So that's why -- so '25 is higher than it normally would be, and we're happy that it is. So we're going to continue on with hedging '26 here, Jerry, as we move forward. So there isn't a change in strategy with respect to that, and we'll continue to move -- to hedge more volumes as we move forward here.

It's just the pace looked a little slower since the quarter end, and I shouldn't take that as indicative of the pace going forward is what you're seeing.

Yes. Okay. I'll let -- maybe I'll let Tavis just elaborate a little bit more on this, Jerry.

Yes, Jerry, in the MD&A, we're disclosing just the financial transactions that we've done subsequent to the year-end. But we've also been fixing some of our gas with physical deals. So -- and we'll be presenting our new marketing slides later today, so you'll be able to see where we're at.

Perfect. Yes, perfect. That's a great answer. And just to sneak in 2 quickies. Cascade at current electricity prices, is there any parallel you could draw to what that would be on a gigajoule basis? And the last one is, when you look at your CapEx choices over the course of the year, is the objective to keep debt flat for the year or to have it flat or lower? Are you using that as one of your disciplines, not just price? That's it for my questions.

So as far as Cascade goes, yes, we don't disclose the details of the contract because it's confidential. But certainly, current power prices, we would be doing better than AECO today. So obviously, we want to get that up and running as soon as we can. As far as your second part -- sorry, Jerry, as far as your second question, it was more about allocation of capital for the rest of the year. Is that where you're going, sorry?

Yes, it was your -- I know that, to a certain degree, if prices were a lot better and things look great that -- and conditions were good, spending more in CapEx kind of follows from that. But under a status quo where things are more conservative, is -- are you targeting to keep the debt more or less either here or lower? And I understand that I don't want to tie your hands here. But in general, is that how you would look at the debt levels?

Yes. At this point in time, with the current plans we have, Jerry, going forward and at the current price levels and our protection on our -- that we have on our revenues with all the hedging we've done here, we don't anticipate -- we're not anticipating adding debt. In fact, we expect to pay down debt in the foremost of the year. It is not a total. We look at it -- per se, when we look at the capital program, we think about it as does it make sense to be drilling these wells? They're certainly economic at today's prices, but do we want to blow out that inventory at lower prices and is that the prudent thing to do with shareholders' money? So that's how we'll look at the capital program going forward. But we do, with the current plan, expect to continue to pay down debt at least in the balance of the whole year anyway.

And Jerry, our term loan is amortizing as well, right? We'll be paying about $58 million down on that facility in 2024.

[Operator Instructions] Our next question comes from Chris Thompson with CIBC.

Just a follow-up on the debt discussion at the time of the Repsol announcement you had announced leverage of 1x debt-to-EBITDA by the end of 2025, and that was on better pricing back then. But just wondering when you guys run it using more recent pricing, where do you see yourselves getting to in terms of reaching that threshold?

Well, we expect -- I think we -- for the most part, we expect to be going down from here, Chris, as far as debt-to-EBITDA leverage goes as we move forward under the current plans. So we were targeting -- I think we said in that release, we said something around aiming for the 1x. It'll probably be closer to 26 now with prices, but they were certainly heading in the right direction. Obviously, the price for the Repsol acquisition is up slightly from what we paid. And so that's included in Q4 here $699 million for the acquisition. So that's why we're up a little bit here post close on the leverage, but we expect that to go down, and we expect that will be down under 1x sometime in late '25 or early '26.

Okay. And then just on -- with respect to pricing in this environment, is there a gas price where you would actually shut in production?

When someone wants to pay us to take their production, I think that's a prudent move honestly. Like if AECO goes negative here this summer, we've shown that in the past we're not afraid to shut in production if someone wants to pay me and I can save those molecules and produce in later. So certainly, in that perspective, we would be -- that would be a prudent thing to do, but our operating costs are so low for us, it's -- we're still making money at prices they are today, for sure. So I think it has to be awfully low in that range for us to shut in production as we're aware. It would only be a portion of course.

Okay. Would that be specific to a certain asset in the portfolio or just broad-based shut-ins?

Well, we would look at -- we would probably look at the wells that we can bring on in the past as well, like an easily shut in because when this happens, it's over a weekend generally. When everybody goes home and we're on top of our game here, so we can quickly react to that situation if were to arise. We also have the Empress service that we have, which allows us to -- which should blow out in that case. So it should be very valuable this summer. So we have incremental Empress service that we could also use. But as far as shutting in production, I think for us, it would be -- we'll look at our -- the list of the best wells to shut in that allow us to bring back on because, usually, this is only a short-term thing.

Got it. Okay. And then in terms of actual expansion deferrals or drilling deferrals, at what pricing would you want to potentially delay even bringing some wells on production? Would you intend to build DUC inventory through the summer rather than bringing those wells on? How are you thinking about that?

Yes. We typically have -- we're pretty fast at bringing wells on stream. So our [indiscernible] one the best in the industry is 45 days on average, I think. So -- but we'll look at -- if it makes sense, we will be rushing up to bring wells on production if the price is really bad at the time. But generally speaking, we will continue to bring production on. We won't be holding on the DUCs.

Okay. Then just on the operating costs. You mentioned Q4 came in lower than your potentially modeling and there's some cautious optimism there. But yes, I'm just wondering at what point would you think about updating the slide in your corporate presentation that does look at those costs? Like how much how much data gathering do you think is needed before we are more confident in the direction that that's going?

Let's get a quarter or 2 under our belt here and prove it to you first how's that.

Sure. Okay. All right. And then I guess just on the last thing on the water side. And I noticed that certainly, in the public data, it does confirm a lot of ground water sourcing for the wells. Can you maybe give us a bit more color just on operationally, how does this work? Like do you have to pull that water up, put it in reservoirs, move it to pad sites? Or does it just go from the well directly to the fracking crew? Like just help us understand that a little bit better, please.

Sure. I'll get Lee to talk to that here. Lee Curran?

Sure. Yes. Thanks for the question. Not all of our candidates that are branded by the same iron. So it's a bit of a complex formula. We do -- we have material infrastructure of bits and C-Rings and storage mechanisms linked flat line. So at the end of the day, we're generally not limited by the short-term productivity of the aquifer. We have a pretty substantial network of service storage containment that those aquifers produce to. Our current program, we're usually 3 to 4 months out on our preplanning of most of that system and weather impacts, we'll adjust sometimes on the fly, whether we got to pump it or haul it. So at the end of the day, when we look at the numbers and we had a conference call with various GLA ministers yesterday, surface water per se is going to be in dire shortage in the province, primarily in the southern part of the province and the Oldman Wild River [indiscernible] water sheds. So we're outside of those areas, which is beneficial. But the focus is going to be surface water. So those that are on large volumes from lakes and rivers and to have to get their DUCs in a row. We utilized 0.3% of our water last year from surface water sources. Those were just a couple of, I think, just where we pull water out of existing borrow pit. So our 99.7% of our water was sourced either by our recycling initiatives with our market and water wells, grab water aquifers. And although those aren't completely immune per se, they're further down the line, and we're looking at other ways to further enhance protection in the event that -- in this drought situation gets even more severe.

And when you say that they're not immune, are you referring to not immune to like government-issued curtailments? Or just not immune to shortage? And I guess, do you have a sense of how many years out would you feel an impact if conditions didn't improve?

The immunity would all be on a regulatory basis. The aquifer productivity because most of them are -- the terminology is not necessarily consistent, but their medium to deep aquifers. We have one shallow water producer, but the lion's share of our water comes from deep aquifers from recharges decades out. So it would be a regulatory constraint. But again, the government of Alberta is pretty sophisticated on their understanding of the water resources in the province. So I would say our level of immunity is very high. It would just become a situation where maybe there is extreme fire situations where they would lots -- various industrial sources of water or things like that, it would be very much an outlier. And of course, our flow back to our recycling initiatives are, I would say, that's a base piece of our business.

Our next question is a follow-up from Jerry McGahee an investor.

JP, this is because of some of the content of the Q&A, you had touched on, if AECO were to go negative, and that might have us shut in some production. And you then did mention Empress and all that. So I think that's part of the answer. But to my question but, I just would like you to elaborate a little bit, so I'll give you the question. I think that there's been considerable effort put in over the last few years to be prepared for particularly the volatility in pricing in AECO. And I think that we actually have a bit of a drag cost, which we offset. But in order to be prepared, in other words, built into our existing run rate is a certain optionality that costs money to maintain. So are not we extremely prepared for AECO volatility or weakness, specifically if it went negative or anything like that? So that -- I'll leave the question there because I think it's not well phrased, but I think you know what I'm asking.

Yes. So we obviously don't have exposure to AECO essentially. And -- we have, like you said, taken great care not to be exposed to AECO. Our -- all our gas is sold elsewhere. So to the extent that AECO goes negative, it's just an opportunity, right? We'll do shut in and take advantage of and save that gas. But for a future, that's the only reason we would do it, and it would be very, very short-term, I'd anticipate. So my comments around that -- we've done that in the past, right? We've shut in over a weekend. So the transportation costs we incur include a little bit of Empress -- extra Empress service that we have that about $0.19 GJ cost us to have that service. So it's a very cheap insurance to get us out of AECO should we have anything that's not diversified from the market. So that -- if prices are equal, were to drop significantly below or even go negative, we certainly have the opportunity then to either monetize the value of that and/or shut in or do whatever we want, but we are very flexible here. So we will do that. So I think the point of this is that we don't have really any exposure to AECO in a sense, but we might want to react to it to be and take advantage of it if it presents itself, right?

I'm showing no further questions at this time. I would now like to turn it back to JP Lachance.

Okay. Well, thanks, folks, for attending the conference call. We'll get back to you next quarter. Thank you very much.

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