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 speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw a question, please press star 11 again. 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 Jean-Paul 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 of 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. 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 multitude of quality 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. They'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. 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. Certainly, operating cost reduction will be a focus for Peyto in 2024. Although the acquisition and the metrics of the deal are great, it's not to be outdone 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 costs of CAD 1.15 per MCFE, or if you include the acquisition, PDP FD&A was a total of CAD 1.21 per MCFE. 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. It sort of points to the underlying qualities of the business. One of those qualities is, of course, our industry-leading field costs, which helped us to yield a solid $3.51 per MCFE field netback. When you combine that with our FD&A, it yielded us a 2.9x PDP recycle ratio for the year. 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 one-time costs relating to acquisition financing and integration that translate 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. 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, Alberta needs right now. It will slow us down. And there is a real concern around the 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 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- and 10-year turnaround. It's broken up into two parts. One is in April, and the balance is September. Those costs are included in our budget, and we expect there'll be minimal production impacts over those quarters. But of course, until we get under the hood, we'll never really know. Longer term, we're still very optimistic about natural gas prices. We believe the startup of LNG Canada and the buildout 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 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, against low prices. So that gives us the confidence to execute our capital program, pay our dividend, and pay down some debt over the balance of the year. One of those diversification markets is the 60,000 GJ a day or 52 million cubic feet a day of gas supply agreement that we have to the Cascade Power Project. 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 startup problems, and they are continuing to work through the commissioning stages, and we expect to be providing them gas sometime here in the second quarter. So that kind of wraps it up. Before I go to some questions from the phone or overnight from emails, 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 remaining of the year. Yeah, sure, JP. Been a very busy four and a half 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 introduce the Peyto culture and explain the company's hands-on and accountability philosophies. As we sit here today, I can comfortably say that a large majority of those folks have embraced this philosophy. What Peyto gets out of that is production-focused and cost-conscious individuals operating the company's assets. Ironically, I guess a long stretch of minus 40 degrees Celsius weather really helps to bring a team together. 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. There was so much out there that we wanted to do, could do, and hoped we could do, so. 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 results so far 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 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 old and 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 Oldm an area. This included diverting a compressor station from the Edson gas plant into the much closer Oldm an gas plant. And the second project effectively gave us some swing capability to move gas out of the MedLodge plant into either Oldm an or Swanson. Here, moving into 2024, we've done two more infrastructure projects. In January, we completed a project, to divert 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. The second project is similar to the one I mentioned we did in December, where we added some swing capability between MedLodge, Oldm an, and Swanson. We're currently waiting on regulatory approval to do a large header modification that will tie in large-diameter infrastructure between Oldm an, Swanson, and the Edson gas plant. This is a precursor to a deep bottlenecking project we are planning later this year that will connect Swanson infrastructure. This, again, is to accommodate drill plants 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 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 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, seems, weekly coming up with new ideas of things we can do. We'll execute on those as sort of project steam, 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, coming 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 on the floor. Thank you. As a reminder, to ask a question, please press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while we compile the Q&A roster. Our first question comes from Amir Arif with ATB Capital Markets. Your line's now open. Thanks. 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 unit OpEx over one year, two years? Thanks, Amir. Yeah, I think the only way I would think about this, and it's a bit early to tell exactly what we're going to see here, so 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 how we see the business changing over the next three years. I think it's slide 21 in the January presentation. There has a little bit of color around our cash costs, excluding royalties and taxes. It gives you a sense of how we feel the total in aggregate will be. So we, of course, expect some kinds of reductions, 5%-10%. It's not unreasonable, but I think we need to see some history here first, to be fair, Amir. Yeah, fair enough. Appreciate that color. And then a question on the hedging side. I'm 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 hedging 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. And so it's not all just financial. So I think we'll continue that sort of mix as it will 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, where 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. But just in terms of the incremental gas volumes, are those going to be mostly financial, or do you plan to keep a similar mix? To the extent that we can 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 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 lands in terms of the EUR per well that we saw on those wells? Yeah, obviously, we had to get to drill those first few wells. These were wells that we would have had locations where we could even use our own surfaces or something that we had prepared, so. But maybe I'll let Riley talk to the specifics around the species mix there. Yeah, so those wells were predominantly Notikewin well. There was also a couple of Upper Falher wells as well Bluesky as a well 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 Wilr ich, Dunvegan, and a lot of other plays. So yeah, it definitely is upset at 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 as 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 as really high-caliber results, so. Terrific. Thank you. Yeah. 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. Thank you. Thank you. One moment for our next question. Our next question comes from Michael Harvey with RBC Capital Markets. Your line's now open. Yeah, sure. Good morning. 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 2023 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? Well, maybe get Riley to answer that question here. I think, generally speaking, our location counts would include what we expect to drill for length, but maybe Riley's on our reserve report anyway, which looks like. Yeah. So I mean, I would expect that our horizontal length will continue to increase slightly here over the next couple of years. 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 what we've been able to book on those lands is actually mostly, call it, mile and a half and two-mile wells. So yeah, 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 of how we were actually drilling wells. By virtue of how we booked the Repsol assets and everything else this year, it is fairly reflective of the longer laterals in the reserves, so. Great. Thanks, guys. Thanks, Michael. Thank you. One moment for our next question. Our next question comes from Gerry McCahey, an investor. Your line's now open. Yes. My first question pertains to the pre and post-Repsol comparison of the value of our liquids. Before Repsol, the numbers seemed 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, 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, 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. The ethane in the Repsol lands, for instance, is a lower value than the percentage condensate in the legacy Peyto production. Yeah. Hi, Gerry. So 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'll help increase our utilization at Edson, and 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 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, 2026 to October 26, 2026. That would be slower than the normal pace that we've seen in the past. So I'm just curious if that represents any change in the approach or if it's well, I'll let you answer that. Sorry. Yeah. So no, we don't. If you look at our past, where that's 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 are still going to take 2026 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 2025 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 2025 is higher than it normally would be, and we're happy that it is. So we're going to continue on with hedging 2026 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. 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. Yeah. Yeah. Perfect. That's a great answer. And just to sneak in two 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. 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 April 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 As far as your second question, it was more about allocation of capital for the rest of the year. Is that where you were going? Sorry. Yeah. It was, you know, that to a certain degree, if prices were a lot better and things looked great and conditions were good, spending more in CapEx kind of follows from that. But under a status quo where things are more conservative, 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 and our protection that we have on our revenues with all the hedging that we've done here, we're not anticipating adding 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. We do, with the current plan, expect to continue to pay down debt, at least in the balance of the whole year anyway. Yeah. And Gerry, our term loan is amortizing as well, right? We'll be paying about CAD 58 million down on that facility in 2024. Okay. Thank you very much, and great job through the quarter, team. Thank you. Thanks, Gerry. Thank you. Once again, as a reminder, to ask a question, please use STAR 11 on your telephone. Again, that is STAR 11 on your telephone to ask a question. One moment for our next question. Our next question comes from Chris Thompson with CIBC. Your line's now open. Yeah. Good morning. 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 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, I think, 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 our current plans. So we were targeting I think we said in that release, we said something around aiming for the 1x, probably closer to 2026 now with prices, but we're 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, the CAD 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'll be down under 1x sometime in late 2025 or early 2026. Okay. And then just 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. If April 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 them later. So certainly, in that respect, that would be a prudent thing to do. But our operating costs are so low for us, we're still making money at prices they are today, for sure. So I think it'd have to be awfully low in that range for us to shut in production, as it were. And 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 probably look at the wells that we could bring on the fastest as well 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, which should blow out in that case, and so 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 the list of the best wells to shut in that will 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? Yeah. We typically, we're pretty fast at bringing wells on stream. So our supply downstream's one of the best in the industry at 45 days on average, I think, still. But we'll look at if it makes sense; we won't be rushing out to bring wells on production if their price is really bad at the time. But generally speaking, we'll continue to bring production on. We won't be curtailing it. We won't be holding onto DUCs, as it were. Okay. Thank you. Just on the operating costs, you'd mentioned Q4 came in lower than your potentially modeling, 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? 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 two under our belt here and prove it to you first. How's that? Sure. Okay. All right. 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 groundwater 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 fracking crew? Just help us understand that a little bit better, please. Sure. I'll get Lee to talk to that here. Lee, correct? Sure. Yeah. Thanks for the question. Not all of our candidates are kind of branded by the same iron, so it's a bit of a complex formula. We have a material infrastructure of pits and C-R ings and storage mechanisms, lay-flat lines. 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 surface storage containment that those aquifers produce too. On a current program, we're usually 3-4 months out on our pre-planning of most of that system, and weather impacts will 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 GOA 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 Oldm an, Wild River, and the Red Deer River watersheds. So we're outside of those areas, which is beneficial. But the focus is going to be surface water. So those that are pulling large volumes from lakes and rivers, they're 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 of instances where we pulled water out of existing borrow pits. So 99.7% of our water was sourced either by our recycling initiatives, which are market, and water wells, groundwater aquifers. 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 this drought situation gets even more severe. When you say that they're not immune, are you referring to not immune to 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? Oh, the immunity would all be on a regulatory basis, the aquifer productivity, because most of them are the 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 the recharge is 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 would be very much an outlier. And of course, our flowback, our recycling initiatives, are, I would say, bulletproof. That's a base piece of our business, so. Okay. That's good. Great. Thanks. Oh, sorry, JP. Go ahead. Well, thank you. Bye. Bye. Thank you. One moment for our next question. Our next question is a follow-up from Gerry McCahey, an investor. Your line's now open. 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 that might have us shut in some production. You then did mention Empress and all that. 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 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 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 say, taken great care not to be exposed to AECO. All of our gas is sold elsewhere. So to the extent that AECO goes negative, it's just an opportunity, right, that we can 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 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 extra Empress service that we have, but about CAD 0.19/GJ costs us to have that service. So it's fairly cheap insurance to get us out of AECO should we have anything that's not diversified to another market. So if prices at AECO 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 with it. 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 take advantage of it if it presents itself, right? Yeah. Thank you very much. Okay. Thanks, Gerry. Thank you. I'm showing no further questions at this time. I would now like to turn it back to J.P. 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.