Good day and thank you for standing by. Welcome to the Peyto's Year-End 2023 Financial Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [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 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 quarterly succession plans, 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 costs down, owning and controlling our infrastructure, securing our revenues through hedging and diversification, and returning profits back to shareholders. [Technical Difficulty] last year and last year was the acquisition of the Repsol assets. I'll [Technical Difficulty] the nitty-gritty details of the deal because by now you've heard it all, the multimode of quality locations we essentially can have to pay for, the synergies with the infrastructure in the field, and the practicalities that is 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 -- 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 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 outdone by the various active 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 costs of $1.15 per mcfe or if you include the acquisition, PDP FD&A was a total of $1.21 per mcfe. 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 with Nimex 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 -- of course, is our industry-leading field cost which helped us to build a solid $3.51 per mcfe field netback. And when you combine that with our FD&A, it yielded us 2.9 times PDP recycle ratio for the year. And I think that `competes to best in class. We did have a little noise in the quarter with our cash costs. Our 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 the -- relating to acquisition financing and integration that translates 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 so 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 cooperation of the spring and summer weather. Let the rains come, which, of course Alberta needs right now, it will slow us down. And there is a real concern around drought conditions in Alberta. If you read the recent Peyto monthly report, you'd know we don't typically use water from surface sources. We drill water wells for our development program, and we use a lot less water than most because of the quality of our reservoirs. And of course, we have a flowback recycling program that we're trying 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 1 in 10-year turnaround. It's broken up into two parts. One is in April and the balance 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 to start-up of LNG Canada, build-out of LNG egress in the US over the next couple of years. It is constructive to the commodity and the 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 forecasted gas volumes fixed against oil 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, 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 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 the -- overnight from the e-mails, Todd, maybe I'll 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 had 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 two thirds 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 the 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 we felt like kids in a candy store. So much out there that we wanted to do but do-- But initially, well optimization began immediately following the acquisition. We started seeing gains in the first month. For the most part, things were 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 runtime. The press release had mentioned us looking at several initiatives to improve reliability following the 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 runtime of 99%. So we're taking that expertise and applying it to the four operating plants that we purchased and we're seeing [Technical Difficulty] and reliability and reduced operating costs. With respect to operating costs, we were modelling slightly higher cost 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 three 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 all that new production at underutilized gas plants, one of the things we're focusing on. And once we received regulatory approval in December, we were able to tie two Repsol pipelines into Peyto pipelines in the Oldman area. This included diverting a compressor station from the Edson gas plant into much closer Oldman gas plants. And the second project effectively gave us a swing capability to move gas out of the Med Lodge plant into either Oldman or Swanson. Here, moving into 2024, we've done two more infrastructure projects. In January, we completed a project to deliver gas from Cecilia over to Wild River that helped to offload the currently at 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 Med Lodge, 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 de-bottlenecking project we are planning later this year that will connect Swanson infrastructure. This, again, is to accommodate drill plant in the area, but again gives options to move gas in and out of plants as needed, especially during upsets 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 volume 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 four or five other projects that we're either waiting on regulatory approval or internal scoping and cost estimating. They may or may not come to fruition, but it's better to have them shovel ready as it were. And we're always -- team's weekly coming up with new ideas of things we can do. And we'll execute on those [Technical Difficulty] context theme 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 as I said, coming up with new ideas.

Okay. Thanks, Todd. 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 on the line.

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

Good morning, guys. I appreciate the color on the different projects you're doing on the operating cost front. Just curious, could you help us quantify what the impact could be over the year? I mean, I understand it's only been a few months, but should we be thinking about a 5% or a 10% improvement in that OpEx over one year, two years?

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

Yeah. No, fair enough. I appreciate that color. Just and then -- a question on the hedging side. And just given that you're a significantly larger gas producer now, historically, you've focused mostly on financial contracts for your hedging. 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 and diversification?

Yeah. 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. 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 and 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.

Yeah. And then just in terms of the incremental gas volumes, is it -- those can be mostly financial or do you plan to keep a similar mix?

To the extent that we can -- we get good value for them, we'll consider them for sure. Yeah. Physicals.

Sounds good. And then just a final question on the eight wells that you had drilled on the Repsol lands, better EURs on those wells than your historic standalone 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 lines in terms of the EUR per well that we saw in those wells?

Yeah. Those -- obviously we had to get -- to drill those first few wells. These were wells that we would have had locations where we could usually use our own or something that we had prepared. So I'll let Riley talk to the specifics around the species mix there.

Yeah. So those wells were predominantly Notikewin wells. There was also a couple of upper Falher wells as well in standalone there. So I wouldn't say, it -- total cross-section of what we have out there, there is obviously a lot of Wilrich, Dunvegan, and a lot of other plays. So yeah, it definitely is up to this point. 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 good results out of those wells. So I think overall here sort of from last year into the first half of this year, the cross section we're seeing is pretty representative and it's holding up sort of where we would expect is really high caliber results.

Terrific.

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

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

Yes, sure. Good morning, and thanks for taking the question. So just a quick one on your horizontal well length. So it looks like your wells got quite a bit longer in '23 just after years of being reasonably flat, 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 has got -- on our reserve report, which -

Yeah. 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 as extended reach is going up. Obviously, with the addition of the Repsol lands, it kind of gave us, obviously, a reset. And so our -- what we've been able to book on those lands is actually mostly, call it, mile and half and two mile wells. So yeah, 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 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 Gerry McCaughey, an Private Investor.

Yeah. So my first question pertains to the pre and post Repsol comparison of the value of our liquids. The -- before Repsol, the numbers 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 were -- rather than looking on 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 proportionately 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?

Yeah. So hi, Gerry. 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 pointed out, a fair bit of that -- and it was in the original presentation, is a fair bit. But some of it is -- about 2,000 barrels of 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 are going to -- rather than paying someone to remove Ethane, which we really get no much -- 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. It will also lower our cost structure. So that will sort of right 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 we think about an increase in value to us.

Right. Okay. That's great. And then 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, 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.

So no, we don't. If we take a look at our past, we're less -- sort of three years out, we would normally be hedging three 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 in that 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 -- 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, Gerry, 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.

Yeah. 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 saying?

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

Yeah, Gerry, 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. And we'll be presenting our new marketing slides later today, so you'll be able to see where we're at.

Perfect. That's a great answer. And just to sneak in two quickies, Cascade at current electricity prices, is there any parallels you can 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. Thank you very much.

So as far as Cascade goes, yeah, we don't disclose the details of the contract because it's confidential. But certainly, current power prices, we'd 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, Gerry, as far as your second question, it was more about allocation of capital for the rest of the year. Is that where you're gone, sorry?

Yeah, 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 we're -- 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?

Yeah, at this point in time with the current plans we have, Gerry, going forward and at the current price levels on our protection on our floor -- that we have on our revenues with all the hedging we've done here, we don't anticipating -- we're not anticipating any debt. In fact, we expect to pay down debt in the fullness of the year. It is not a toggle. 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.

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

Thank you very much, and great job through the quarter, team.

Thanks, Jerry.

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

Thanks for taking my question here. Just to follow up on the debt discussion. At the time of the Repsol announcement you'd announced leverage as one times 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 drawing down from here, Chris, as far as debt to EBITDA leverage goes as we move forward under the current -- under our current plans. So we were targeting -- I think we said in that release, we said something around -- aiming for the one times. Probably closer to 26 now with prices, but -- and we're certainly headed 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 at $699 million for the acquisitions, 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 one times 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, but are afraid to shut in production if someone wants to pay me. I can save those molecules and produce them later. So certainly in that respect, we would be. That would be prudent thing to do. But our operating costs are still low for us. We're still making money at the prices they are today for sure. So I think it has to be awfully low in that range to -- for us to shut in production is -- 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 could bring on the fastest as well like, -- and 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 it were to arise. We also have the Empress service that we have which allows us to grow -- that should blow out in that case. And so it should be very valuable this summer. And so we have incremental interest service that we could also use. But as far as staying in production, I think for us it would be we'll look at our -- the list of the best wells to shut in to 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, what pricing would you want to potentially delay even bringing some wells on production? Would you intend to build duck inventory through the summer rather than bringing those wells on? How are you thinking about that?

Yeah, we typically have -- we're pretty fast at bringing wells on-stream. So our Peyton team -- one of the best in the industry is 45 days on average still. So -- but we'll look at -- just the extent, we won't be rushing out to bring wells on production if their price is really bad at the time. But generally speaking, we will continue to bring production on , we won't be holding on with that .

Okay. Thank you. And then just on the operating costs, you mentioned Q4 came in lower than you're potentially modelling and there's some cautious optimism there. But yeah, 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 data gathering do you think is needed before we are confident in the direction that that's going?

Let's get a quarter or two under our belt here and prove to you first, how's that?

Sure. Alright. 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? 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 fracs and crew? Just help us understand that a little bit better, please?

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

Sure. Yeah, Thanks for the question. Not all of our candidates are branded by the same . So as a complex partner, we do -- we have a material infrastructure, that's steering and storage mechanisms, . So at the end of the day, we're generally not limited by short term productivity of the aquifer. We have a pretty substantial network of surface storage containment that those aquifers produce too. At current program we're usually three to four months out on our preplanning, most of that system and weather impacts will adjust sometimes on the fly whether we got pump at our -- or haul it. So at the end of the day, when we look at the numbers and we had a conference call with various ministers yesterday. Surface water per se is just going to be in dire shortage in the province, primarily in the southern part of the product and the Oldman and Wild River area, Brazeau river water sheds. So we're outside of those areas which is beneficial. The focus is going to be surface water. So those that are on large volumes from lakes and rivers that are going to have to get their ducks in a row. We utilized 0.3% of our water last year from surface water sources, those were just a couple, I think. Just when we pump water out of existing water pit. So our -- 99.7% of our water was sourced either by our recycling initiatives which are market and water wells, groundwater aquifers, and -- although those are 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 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?

All of this -- the immunity with all the -- on a regulatory basis, the outcome for productivity because most of them are -- terminology is not necessarily consistent, but they're medium to deep aquifers. We have one shallow water producer, but the lion's share of our water comes from deep aquifers which [Technical Difficulty] decades out. So it would be a regulatory constraint. But again, the government of Alberta is pretty sophisticated on their understanding of the water resource in the province. So I would say our level of immunity is very high. It would just become a situation where maybe there was extreme fire situations where they would want various industrial sources of water or things like that. It'll be very much an outlier. And of course, our flowback, our recycling initiatives are, I would say, -- that's a base piece of our business.

Our next question comes from Gerry McCaughey, Private Investor.

Hi, 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 a shut in some production and you then did mention Empress and all that. I --and so I think that's part of the answer 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 Heiko and I think that we actually have a bit of a drag cost which we offset in order to be prepared. In other words, built into our existing run rate is a certain optionality that cost 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.

Yeah. 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, all of our gas sold elsewhere. So to the extent that AECO goes negative, it's just an opportunity right to cut in and take advantage of -- to save that gas. But for future, that's the only reason we would do it. And it would be great in short term I would anticipate. So my comments around that. And we've done that in the past, right? We've shut in over weekends. So the transportation costs we incur include a little bit of Empress -- extra Empress service that we have that are about $0.19 GJ cost us to have that service. So it's very cheap insurance to get us out of AECO should we have anything that's not diversified into the market. So that -- if prices or AECO were to drop significantly below at -- 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 to do. 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 and be -- and take advantage of it if it presents itself, right?

Thank you. 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. I will get back to you next quarter. Thanks very much.

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