Welcome to Ovintiv's 2024 Fourth Quarter and Year-End Results Conference call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing Star 1. For members of the media attending in a listen-only mode today, you may quote statements made by any of the Ovintiv representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Ovintiv. I will now turn the conference over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest. Thanks, Joanna, and welcome everyone to our Fourth Quarter and Year-End 2024 Conference Call. This call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the beginning of our slides and in the disclosure documents filed on EDGAR and SEDAR+. Following prepared remarks, we will be available to take your questions. I will now turn the call over to our President and CEO, Brendan McCracken. Thanks, Jason. Good morning, everybody, and thank you for joining us. We are very pleased with our 2024 results, and we are very excited about 2025 and our future. Over the past several years, we have executed on our durable return strategy, and we begin this year with one of the most valuable premium inventory positions in our industry. We combine that with our team's culture and expertise to convert resource to free cash very efficiently. We have built this position in a very shareholder-friendly way that sets us up to generate exceptional return on capital for a long time to come. We now have a more focused and more profitable portfolio with anchor positions in the Permian and Montney, the two largest remaining undeveloped oil resources in North America. These assets are complemented by our low-cost, low-decline, high-free cash-generating asset in the Anadarko Basin. Our work to build inventory depth over the past several years means we now have close to 15 years of premium inventory in the Permian, close to 20 years of premium oil inventory in the Montney, and over a decade in the Anadarko. We are also seeing the benefits of our efficiency gains show up in our capital and cash costs. We're delivering oil-type curves on a barrel-per-foot basis that are as good or better year over year in each of the three assets. Those efficiency gains are how we are holding our 2025 guidance at 205,000 barrels a day, completely making up the gap from selling 29,000 barrels a day in the Uinta and buying 25,000 barrels a day in the Montney. We believe our ability to continue to generate superior returns will be differentiating. With this inventory and our demonstrated execution excellence, we're set to generate over $2 billion of free cash flow this year, and we are confident we can continue to do this durably for years to come. Our 2024 results show another year of execution excellence and delivery against our strategy. In short, we delivered tremendous profitability, enhanced our capital efficiency, bolstered our financial strength, and high-graded our portfolio. These results demonstrate that our strategy is working and our execution excellence is translating into increased value for our shareholders. We beat and reset our targets three times over the course of the year, enabling us to produce more of our products without investing more capital. Our initial guidance for 2024 had us delivering 205,000 barrels a day of oil and condensate for $2.3 billion. We came in right at the capital guide, but it came with an additional 6,000 barrels a day of oil and 25,000 MBOE /d of total production. Our full-year free cash flow was $4 billion. We generated free cash flow of approximately $1.7 billion, up 50% year over year, of which more than $900 million was returned directly to our shareholders. We continued to lead the industry by delivering efficiency gains in each of our assets. Completion design innovations, record-setting execution performance, leading productivity per lateral foot, and base decline management are a few of the areas contributing to our exceptional return on invested capital. In November, we high-graded our portfolio with the announcement of an oil-rich acquisition in the core of the Alberta Montney and the divestiture of our Uinta assets. Both deals have since closed. In addition to adding 900 high-quality Montney drilling locations, these transactions significantly enhance our capital efficiency and free cash generation, allowing us to pay down debt faster and increase returns to shareholders. Importantly, we also continue to make progress on debt reduction during the year, ending the year with $5.4 billion of net debt, a decrease of more than $320 million. Our strong execution in 2024 has set us up for continued success in 2025. Our strong operational performance during the fourth quarter delivered oil and condensate volumes averaging approximately 210,000 barrels per day, beating the high end of our guidance. The production beat was driven by the Permian and the Montney, where we continue to see strong well results and outperformance from our base volumes. We did come in slightly below the low end of our guidance range on natural gas and NGLs due to a value-based decision to reject ethane in the Anadarko and some temporary winter weather impacts in the Montney. Our fourth quarter capital investment was approximately $552 million, in line with the midpoint of our guidance range. We also meet or beat per-unit cost guidance on every item, continuing to build on our track record as an industry-leading operator. Our fourth quarter cash flow per share at $3.86 beat consensus estimates by about 7%, and our free cash flow totaled more than $450 million. All in all, another strong quarter both operationally and financially, which allowed us to enter 2025 with significant momentum. I'll now turn the call over to Corey to discuss our 2025 plan in more detail. Thanks, Brendan. In 2025, we will continue to focus on maximizing the returns on our invested capital to increase our free cash flow, our shareholder returns, and further reduce our debt. This means we are leveraging our multi-basin portfolio and focusing 100% of our investment in our most oil and condensate-rich areas. Each of these three areas is expected to generate program-level after-tax returns of approximately 65%-75%. Although the value drivers for each asset are different, they all compete for capital within our portfolio. We expect to generate about $2.1 billion of free cash flow in 2025, assuming commodity prices of $70 WTI and $4.9x gas. This represents an increase of more than $300 million year over year and a near doubling of free cash flow from 2023. Our 2025 free cash flow yield of approximately 18% and a cash return yield of 10% are very competitive in today's market across both industry peers and the broader economy. As a reminder, we expect to restart our share buyback program in the second quarter with first-quarter free cash flow. Our enhanced capital efficiency will allow us to optimize our capital structure at a faster pace, decreasing our debt and reducing interest expense. By year-end, we expect our total debt to be well below $5 billion, making significant progress towards our $4 billion total debt target. Even though we're investing in the most oil-rich parts of our acreage, our production profile is about 50% gas, and as a result, we have significant torque to higher gas prices. We've been very intentional in moving our price exposure away from weaker pricing hubs like AECO and Waha to diversified downstream markets in the U.S. and Canada. We have done that both physically by acquiring firm transportation out of the basin and financially with basis hedges. In 2025, about three-quarters of our natural gas will price outside of AECO and Waha. This means we stand to benefit significantly from higher gas prices, even if AECO and Waha prices remain weak. This year, for every 50-cent move in Henry Hub gas prices, we expect to generate $225 million more free cash flow. As a reminder, our price exposure gets even better in the fourth quarter with the commencement of our service on the Matterhorn pipeline in the Permian for 50 million cubic feet per day. Access to premium resource is an essential component to generating durable returns. We recognize this early and have done a lot of work over the last few years to identify opportunities to extend our inventory runway through organic appraisal and assessment efforts, bolt-ons, and acquisitions. As Brendan highlighted earlier, we've built an enviable premium inventory position across our portfolio. As a result, we can execute our business plan and generate superior returns for our shareholders for a long time to come. We remain very pleased with the value accretion we've realized from our Permian acquisition in 2023, and we expect the same from our recent Montney acquisition. At roughly $1 million per well location, our Montney deal will deliver strong returns and compares favorably with many of the recent deals we've seen in the broader North American market. We've been very intentional in building a high-quality portfolio with deep inventory in each asset and in each product, and we have demonstrated that we are disciplined stewards of our shareholders' capital. I'll now turn the call over to Greg, who will speak to our 2025 guidance and operational highlights. Thanks, Corey. Maximizing capital efficiency and free cash flow remains a primary focus for our teams in 2025. As Corey mentioned, we are focusing 100% of our investment on oil and condensate, but we also have significant free cash flow upside to stronger gas prices. About 85% of our capital will be focused on our two anchor assets, the Permian and the Montney, supported by free cash flow from the Anadarko. Our 2025 program will deliver 205,000 barrels of oil and condensate per day and total production volumes of 595,000-615,000 BOE per day for about $2.2 billion of capital investment. Our full-year total production will be slightly lower than if both the Montney and Uinta transactions had closed on January 1st. Additionally, we've elected to reject ethane in the Anadarko for the majority of the year, and we now expect higher Canadian royalties. These items will also modestly affect our volumes. The decision to reject ethane supports our realizations, and the higher royalties are due to higher gas prices, so the net result is free cash flow accretive. We expect our first quarter production to average approximately 585,000 BOE per day, including about 202,000 barrels per day of oil and condensate. The production impact from the Montney and Uinta transaction close timing is roughly 3,000 barrels per day during the quarter. Oil and condensate production will stabilize in the second quarter and remain flat through the end of the year. Our capital spend will be highest in the first quarter, largely due to transaction close timing impacts, higher completions activity in the Permian, and temporary drilling activity in the Montney that we inherited from the seller. Importantly, the capital efficiency of our 2025 development program is repeatable in 2026 and beyond, allowing us to sustain approximately 205,000 barrels per day of oil and condensate production with capital investment of about $2.2 billion. Let's shift now to the asset-level development programs. In the Permian, capital efficiency and free cash generation remain the top priorities for our program as we work to drive efficiency in every aspect of our operations. Ovintiv is consistently one of the highest productivity, lowest cost operators in the basin. We recently received third-party recognition of our basin leadership from JPMorgan by being awarded the 2024 Order of Merit for Midland Basin performance. Our 2024 drilling speed averaged more than 2,000 feet per day and was roughly 18% faster than the 2023 program average. On completions, our full-year average completed feet per day was about 3,850. This was 20% faster than our 2023 program average. These cycle time improvements result in lower well cost. Our pace setter D&C cost is among the best in industry at less than $600 per foot. The 145 gross wells we brought online in 2024 continue to paint the type curve. This type curve was unchanged across 2024, and it remains unchanged in 2025. This year, we started with five rigs and will drop to four at the end of the first quarter to bring on 130-140 net wells and hold oil and condensate production at roughly 120,000 barrels per day on average for the year. Our D&C cost is expected to average $600-$650 per foot and is about $25 per foot lower than last year. Our Permian team expects to deliver consistent year-over-year well performance from a similar number of turn-in-lines for less capital. Moving north to the Montney, we are very excited to have the new Paramount assets in our portfolio, and we are working to integrate them into our business as safely and efficiently as possible. So far, the wells are performing very well as expected, and we are looking forward to delivering our first Ovintiv end-to-end designed wells later in the year. As a reminder, we plan to deliver well cost savings of more than $1.5 million per well across the acquired assets by applying our industry-leading data-driven approach to drilling, completion, and production operations. This approach continued to yield positive results in 2024 as we saw steady improvements in our daily average drilling and completion speed. The Montney has the lowest well cost in the portfolio, and in 2025, we expect our D&C cost to average $525 per foot. This is about $25 per foot less than our 2024 well cost. Our 2025 three-to-four rig program of 75 to 85 net turn-in-line will see roughly a third of our activity in the newly acquired acreage, with the remaining activity split between our legacy Pipestone and Cutb ank Ridge areas. The primary driver of value in the Montney is condensate production, and since there is a structural long-term deficit in the Western Canadian market, it should continue to trade tightly to WTI for the foreseeable future. In 2024, the average price realization for our Montney condensate was 95% of WTI. In 2025, with the addition of the new assets, we expect to produce about 70% more condensate, or about 55,000 barrels per day in total, for only 40% more capital. This makes us the second largest condensate producer in the play. As Corey mentioned, we are receiving much higher prices for our Montney gas than the AECO benchmark would imply. In 2024, our average Montney gas price realization was 164% of AECO, or 76% of the NYMEX benchmark. The underlying gas supply and demand fundamentals in Western Canada should continue to improve this year as LNG Canada comes online. Moving to the Anadarko, we continue to benefit from the strong free cash flow generation from the asset, in part due to its exceptionally low base decline rate at about 16% per year. This asset is unique in providing a stable, well-priced stream of production with low operating costs and a minimal stay-flat capital requirement. In 2024, the team continued to make significant progress in lowering well costs by focusing on drilling speed, maximizing lateral length, minimizing casing strings, and maximizing the number of wells per pad. They've taken nearly $100 per foot out of our average D&C cost and are set to deliver an average of about $550 per foot in 2025, a reduction of $100 per foot year over year. Our efforts in the play have not gone unnoticed as our Anadarko asset also recently received the 2024 Order of Merit from JPMorgan. We plan to run an average of 1.5 rigs in the play this year, delivering 25-35 wells. This will essentially hold our oil and condensate volumes at around 30,000 barrels per day on average for the year. I'll now turn the call back to Brendan. Thanks, Greg. In closing, we continue to deliver outstanding results. We're focused on maximizing the profitability of our business, generating significant free cash, and maintaining our strong balance sheet. Our focus on building premium inventory depth, execution excellence, disciplined capital allocation, and driving profitability have positioned our business to thrive on the road ahead. This concludes our prepared remarks. Operator, we're now ready to open the line for questions. Thank you. Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing Star 1. We will now begin the question and answer session and go to the first caller. The first question comes from Gabe Daoud at TD Cowen. Please go ahead. Thanks, hey. Morning, everyone. Thanks for taking my questions. Brendan, I was hoping we could maybe first start with Montney versus Permian. You highlighted pretty attractive returns across the entire portfolio. But from an A&D standpoint, given where acreage and location values are rising too in the Midland, would you say maybe your bias from here would be to add more in the Montney versus Permian if there was a need to add some more inventory? Yeah. Hey, good morning, Gabe. Thanks for the questions. I guess what I'd say at a high level before maybe making a comment on the relative market in the two assets for acquisitions, what I'd say at a high level is it feels really hard to beat what we've done so far. This has been a multi-year effort to assemble the portfolio, and really, I feel like what we're representing today is a new level of portfolio and inventory depth and quality for our investors, and we have a ton of confidence in that portfolio being able to generate the free cash flow that we've pointed to for 2025 for a long time to come, and so it feels really difficult, I guess you'd call it a high bar, to beat that today. And so, in general, our view is anything we would do would be coming from a position of strength, and we're excited about what we've done over the last several years. In terms of the relative, I mean, you've hit it. There's just a massive arbitrage between the two. And at the same time as we were able to do our transaction for right around $1 million in undeveloped location, we've seen prints in the Permian for well north of that. So we think that's value to our shareholders that we're uniquely positioned to be able to access and create for them. Thanks, Brendan. That's really helpful. Thanks for that caller. And then I guess just as a follow-up, you mentioned on the slide a Permian and Montney oil powerhouse. So I guess a good question then off the back of that would just be, how does Anadarko fit into the portfolio longer term? Any updated thoughts, sir? Yeah. And absolutely. If you look at where 85%-90% of our capital is going into the Permian and the Montney, so that is a big part of how we're running the business and prosecuting the strategy. And we've put ourselves in a place here. We've got close to 15 years of premium oil inventory in the Permian, closer to 20 of oil inventory in the Montney, and then over a decade in the Anadarko. And so we really like the role that the Anadarko is filling for us. It's a really valuable asset. And what's really unique about it, and we've highlighted it a couple of times, but perhaps even underappreciated, is the low decline nature of that play. And what that does is it supercharges the free cash that it's generating. So at a 16% base decline, that means we don't have to spend very much capital in there to level that asset out around the 30,000 barrel a day mark this year. It'll start a little lower in Q1 and then build to that 30. But we're really excited about the role that the Anadarko is playing. I would also highlight that's a spot where our type curves are up year over year. And the team's done a great job of getting well cost down and type curves up, which boosts returns. And so whether we're running a rig in the Anadarko or a rig in the Permian or the Montney, they're delivering the same financial outcome for the business, which is very important from a capital allocation perspective. Yeah. Yeah. No, for sure. That's great to see. Awesome. Thanks, Brendan. Thanks, Gabe. Thank you. The next question comes from Doug Leggett at Wolfe Research. Please go ahead. Hi. So I'm a key interest player for Doug Leggett this morning. He is unavailable at this particular time. My first question would be regarding your net debt target. You have a long-term target of $4 billion. You guys reduced by $323 million for the past quarter. I guess what do you kind of project being your net debt target by end of 2025? If you can give me any color on that and how you get to that number. Yeah, absolutely. So I think what we've got in the materials is we're going to get it well underneath the $5 billion mark by the end of this year. If you look at prices on the screen today, it would be in that 4.6-4.7 range by the end of the year, which we're really excited about because that now puts us within spitting distance to getting to that $4 billion target in 2026. So really excited about the trajectory they were on there. And we've pointed in the materials as well, we'll be resuming buybacks in the second quarter here following the pause off the back of the acquisition in the Montney. Really excited that we've been able to kind of reduce that incremental debt that we took on with the acquisition very quickly and get back into the buyback market because we're excited about buying shares at this level. Thank you. Thank you. Thank you. The next question comes from Arun Jayaram at JPMorgan. Please go ahead. Yeah. Good morning. Brendan, you provided an updated inventory analysis across three of your core basins, which points to well into the double digits in terms of inventory depth on the oil side and beyond that on the gas side. Brendan, what do you think this does for you from a strategic standpoint, just having that durable inventory position as we think about future A&D and just other opportunities as we look forward? Obviously, you highlighted maybe $2 billion of free cash flow, a little bit over that at Strip. And maybe the potential for that to continue over time. Yeah. Arun, love the question i think the confidence in that free cash generation and the durability of it, which is the important point that you're flagging. In addition to the inventory depth and quality, which we think is really enviable, we're also seeing lower capital in the business and lower cash costs, which means higher profitability and higher free cash that's coming with that, so it's really a combined effect of providing our shareholders the confidence in that inventory to be able to generate these returns durably, and then just continuing to use our efficiency gains both on the capital and the cash cost side to just drive free cash flow over time. And then, like I say, we're getting a great cash flow per share boost with the buybacks. And the value we're shifting to the equity holder by reducing debt. So it's really kind of an all of the above attack. And you also, I think you hinted at or asked in your question there how that frames it up in terms of A&D thoughts. And I would just say that this makes an already high bar even higher, given what we've been able to do with the portfolio. Great to hear. Maybe my follow-up, if there's one incoming question we've gotten just on the regulatory macro picture, is just maybe the impact of potential Trump tariffs on Canada. I was wondering if you've done some analysis on that and just provide just some general thoughts because I know it's a pretty complicated question just given where we don't have a ton of details here. But I was wondering, Brendan and Corey, if you could maybe help us frame the potential impact. Yeah, absolutely. Look, the assumption we give you at this point, we anticipate a pretty modest impact to our business. And let me kind of dig in, describe it a little bit more. As you flagged, there's still a fair bit of uncertainty about timing. Is there going to be any exceptions? What are the magnitude of the impacts, and how are they going to be expressed in the market? And so what we've done is, as you might expect, sort of a ranging type scenario from sort of a more moderate tariff scenario to a more extreme tariff scenario. And even in the more extreme pictures that we can paint, it is a very modest impact to our cash flow in 2025. Maybe I'll just flag because it might be helpful for folks to understand the different places that we would see tariffs potentially impacting our business. We'd expect to see something in the supply chain. We already have the steel and aluminum tariffs in place. So that largely shows up as an OCTG impact. And remember, here we source all of our OCTG domestically in the U.S., but there could be some bleed-through to domestic prices because of the tariffs on international imports. So we've been proactive in purchasing and pricing a significant part of that 2025 supply chain already, but we don't anticipate that to be a severe effect. On the gas side, of course, we export gas into Chicago and into the U.S. West Coast. And so there could be impacts there, which also could see some bleed-through into the AECO and the Dawn markets. Again, all of this conditional on, are there reciprocal tariffs for the gas that Canada imports? There is a range. And then, of course, all of our condensate, we sell that domestically within Canada. And then finally, the sort of counterbalance point is around foreign exchange. And I would say the consensus view is that tariffs on Canadian imports into the U.S. would strengthen the U.S. dollar relative to the Canadian dollar. And for our business, a lower Canadian dollar is favorable for free cash generation. So you kind of put all those different categories together, and our net-nets scenarios suggest pretty neutral in terms of an impact to our 2025 cash flows, even in that more extreme tariff scenario picture that we can paint today. So watching it closely, clearly, there's a lot of dynamics, but don't anticipate it being a significant impact to 2025 cash flows. Thanks, Brendan. Yeah. Thanks, Arun. Thank you. The next question comes from Neil Dingman at Truist Securities. Please go ahead. Morning, guys. Thanks for the time. Brendan, my question maybe for you or Greg, just again, the op efficiencies are notable. I'm just wondering, when you look at your guide and expectations for this year, I'm just wondering, what are you all thinking sort of service cost versus continued operational efficiencies? It looks like you might have a benefit of both, but I'm just wondering how Greg or yourself are sort of viewing that for at least the remainder of this year. Yeah. Hey, Neil. Absolutely. So I'm going to kick it to Greg. High level, we've got about a low single-digit deflation built into the 2025 program, but the bulk of the gains are true efficiency gains. But I'll kick it to Greg to maybe just highlight a few of the really key ones. Yeah. Thanks for the question, Neil. I mean, I'm just continuing to be impressed with our teams and what they're able to accomplish. 2024 was the fastest year we've ever had in drilling and completion, both in the Permian and in Canada. Maybe just a couple of stats. I mean, 30 of the 35 fastest wells we've ever drilled in the Permian were drilled in 2024. So the team just continues to get significantly better. And that's what's allowed us to continue to drop rig count. We're constantly trying to match up the right number of rigs with the right number of frack crews to be as efficient as possible and take white space off the calendar. Last year, we had six rigs running in the Permian, ended up dropping to five late in the year. And then, as I mentioned in my prepared remarks, we'll be dropping to four rigs here at the end of the first quarter. And all of that's really just trying to sync up the right amount of rig and frac activity. Something that's really impressive, if you were to take the four rigs that we're planning on running for the majority of this year and pair that with one Trimul-Frac crew, we could do 110 to 120 wells with that setup. So almost our full program with what we think today could be accomplished with four rigs and one Trimul-Frac crew. And with the efficiencies we continue to see, I wouldn't be surprised if that becomes the norm for us going forward. So just continue to be really proud of the teams and how fast they're going. But of course, then we believe strongly in level loaded programs and a balanced schedule. So as we get these efficiencies that bring more activity into the year, well, then some of those savings will be reallocated towards the end of the year to continue that level loaded program. But just continue to see great performance, and we think we're going to see even more here in 2025. Great details. Just one last piece. You guys have been busy on the M&A obviously with the Montney. I'm just wondering, Brendan, when you see sort of the Montney footprint now and your Permian footprint, is there still a fair amount of white space that you could fill in? Just wanted on smaller deals. Thank you. Yeah. Hey, Neil, you're a little muffled there, but I think your question was just on, are we going to continue to try and fill in some white space in the Permian and the Montney on the map? And I just sort of wrapped. Yeah. Yeah. Okay. I heard that right. Good. Yeah. I think the answer there is kind of similar to what I described before. We're taking a high bar and raising it even higher in terms of allocating capital towards acquisitions, given the success we've had over the last several years and given the inventory depth and quality that we've created. So I think teams are going to be continuing to do a lot of work on swaps and coring up so that we can drill longer laterals on the footprint that we've already got. I would expect that to continue at a pace, but pretty disciplined around how we're thinking about go forward bolt-ons and acquisitions. Thanks. Thank you. Thank you. Yeah. Great. Thanks, Neil. Thank you. The next question comes from Kalei Akamine at Bank of America. Please go ahead. Hey, good morning, guys. Maybe this question is for Corey. So we appreciate the free cash flow yield sensitivity at 18%. There's kind of a delta versus the street. As you guys were putting that analysis together, where did you find street numbers to be insufficient? Yeah. I'll flip that over to Corey Code. Thanks. Yeah. I mean, we did take a little bit more time to highlight the leverage to natural gas. And I think if you go back, even over the last year or two, we've talked a lot about our oil portfolio. So just reminding people of the significant natural gas exposure that we have. But what you've heard through the call, and if you look at some of the actual results, we've had good, not just capital efficiency, but all of our various elements of cost, I think, have outperformed. So it's a bit of a combination depending on which analyst you look at, whether it's realized price or on the cost side. But I guess the short answer is probably multiple factors contributing to that outperformance on free cash flow. I did think. Yeah. That's fine. I would just add, Kalei. Sorry, Kalei, this is Brendan again. I would just add, overnight with the disclosure that we put out, the team did have some good conversations with a few of the analysts where there were some models that just had some bust in them, and we were able to get those cleaned up and match the free cash projections that we've put out there. Sounds good. Kind of shifting over to the Montney here, looking at your GP&T expense, it's higher than Permian Basin. Can you kind of remind us why it's different? Is it related to ownership of G&P assets? And if so, would you ever consider bringing that fixed cost in-house? Yeah. Hey, Kalei, you've hit on it exactly. There's, generally speaking, in the Montney, a mixed bag of ownership of midstream and non-ownership of midstream. And just the way our midstream has been built out over the decades, it is largely third-party owned. So our realizations on the cost side reflect that. And as far as looking at bringing things in-house, I think we're always looking at every opportunity we can to enhance profitability, but we'd have to weigh that against the cost, of course, of that acquisition. You got it. Thanks, Brendan. Yeah, you bet. Thank you. The next question comes from Greta Drevsky at Goldman Sachs. Please go ahead. Good morning, and thank you for taking my question. Thinking about risk management through volatility, would you characterize a sufficient proportion of your production as covered with your current hedge book, or are you seeking to further reduce unhedged exposure either in your oil or gas portfolio from here? Thank you. Hey, good morning, Greta. Absolutely. We've been running about a 25% hedge book and using largely three ways to put that risk management in place so that we can retain as much exposure while creating a floor. And really, how we think about it is we want to be able to withstand a long period, call it 12 months, of pretty low commodity prices, call it sort of the $40 on WTI and $2 on NYMEX. And that's been the strategy we've been following while we've been delevering. And what we've signaled all the way along, and this continues to be the case, is that as we get that debt down, the need to have that hedge book can shrink even further. I do think as we look out into 2026, we'll continue to be following that hedge strategy, but then thereafter, we can continue to look to drag that down as we get the leverage back into the target range. Great. Thank you. And then also for my second question, the results from Trimul-Frac have been very compelling in 2024. With the 2025 outlook for about 75% of Permian operations utilizing Trimul-Frac, do you see much upside to that estimate in 2025 or 2026, or would you consider 75% closer to the optimal proportion of operations? Yeah. I think we'll continue to see it inch up with time. That's been the sort of track record so far for the team. And I don't know, Greg, if you'd have any other comments there. Yeah. I think over time, that'll continue to come up. The only thing keeping us from doing all of our wells with Trimul-Frac are just physical limitations on the ground. We have situations where you don't have six wells on a pad, or you have six wells that are separated by a road or some other physical thing that prevents you from fracking all six of those at the same time. But we'll continue to inch that up. We'll continue to be very happy with the results we're getting from Trimul-Frac. That's what's allowing us to, we think, complete more feet per day than anybody in industry out there. And so we'll continue to work on that. Great. Thank you. Thanks, Greta. Thank you. The next question comes from Kevin MacCurdy at Pickering Energy Partners. Please go ahead. Hey, good morning, and thank you for taking my questions. My two questions are going to focus a little bit on gas. I appreciate the details on the free cash flow sensitivity to gas prices on slide eight, and we would agree that you have one of the higher sensitivities among oilier companies. But I wanted to ask about the operational sensitivities. Is there a price at which you shift capital to gasier assets or increase overall company activity? Yeah, Kevin, great question. It's actually a really interesting one. And the one point that we've tried to flag for folks, but I think it's meaningful, is when you drill a gas well, you get a whole bunch of, or when you drill an oil well, you get a whole bunch of gas with it. And when you drill a gas well, you get zero oil with it. And so it actually is an asymmetrical capital allocation choice from a value perspective. So what we really like, given where prices and the fundamentals are today, is we like being in maintenance mode. We continue to believe the right allocation of excess free cash flow is to the buybacks and not to growth. And that's because we're getting a better cash flow per share outcome from buying those shares back than we could get by investing that for growth in the business. And so that's sort of first off. And then when you look at the decision between gas and oil, we really like the allocation to drilling oil wells, and then the associated gas upside comes along with it as opposed to saying, "Oh, no, we're going to allocate directly to dry gas." So obviously, there can be a breaking point depending on the fundamentals, but with today's prices, we continue to favor allocating our capital to oil and getting the gas as an associated upside. Appreciate that response. And for a follow-up, you've done a really good job of diversifying your AECO exposure, but do you have any view on how that market develops, hopefully, as more demand comes online locally? Yeah. I think our view has been pretty consistent there, which is we're going to see some benefit from the additional little over 2 BCF/d of offtake off the West Coast. And there's been some color already this quarter from some of the operators and some of the participant companies on timeline there, which is coming up this summer for the first loads, which is exciting. But our view has been that's going to be probably relatively transient as opposed to a structural reset of AECO pricing. And so our strategy has been to continue to diversify gas away from the AECO basin, and I think that'll kind of continue. We inherited a couple hundred million a day of additional AECO exposure with the Montney acquisition. So that's likely to be something you'll see us chip away at between exploring LNG options for that gas, exploring getting more gas into the markets we're already serving, the West Coast and Chicago, but also some of this data center demand optionality that's showing up where we've been in a lot of conversations with a lot of interested counterparties there, which is really exciting. And we think we're in a differentiated place in Western Canada to be a gas provider of choice for some of those projects, whether it's data center or petchem, because of our investment-grade status and because of our deep gas resource in the basin, which can give a counterparty a lot of confidence both financially and subsurface in the resource. That was very interesting. Thank you. Yeah. Thank you, Kevin. Thank you. The next question comes from Dennis Fong at CIBC World Markets. Please go ahead. Hi, good morning, and thanks for taking my question. Maybe the first one is to carry along with the last kind of train of thought there. You kind of mentioned some opportunities to, I guess, I don't want to say necessarily lock in a longer-term or longer-duration contract or pricing, but can you describe, I know historically there's been a few characteristics of these types of, whether it be LNG contract or whatnot, that you've wanted to ensure if that was an attractive option for selling the gas. Can you remind us as to what you'd be looking for in that type of a situation? Yeah, Dennis. I think the first thing to start with is we're interested in having a portfolio of diversification here. We like the idea of not putting all the eggs in one basket, so to speak. And you can see that already we've made with getting to diversified downstream markets today. And so I think going forward, what you should expect from us is a portfolio, and our vision is for that portfolio to have a mix of LNG and a mix of local incremental demand, whether it's, like I said, data centers or petchem opportunities. And so I think we'll see how those deals come together, but what we really like about that portfolio is it not only provides the upside for our realizations, but helps us manage risk. One of the things that's really kind of been a focus point for us is to not wind up signing up for a long-term transportation and processing contract that's fixed into an uncertain market. That's been the focus of our commercial team, to make sure we find ways to manage that diversification risk and not wind up with a long-term service agreement that is underwater for long periods of time. Great. Appreciate that color. I wanted to shift gears a little bit more into the cost side. You've obviously made a lot of progress on operations, obviously with rate of drilling, completion efficiency, the use of Trimul-Frac. I wanted to go into kind of supply chain management. I know that's something that you guys have also been a leader of, obviously with risk around tariffs and so forth. How are you maybe managing around drill pipe, obviously completion material, well, well tubulars, and so forth? Can you remind us as to how your supply chain management group is optimizing efficiencies and maybe trying to manage the risk around trade and so forth? Yeah, great question, Dennis. And that is a piece that we've been a pretty sophisticated player in for quite a while. And I would tell you a lot of the supply chain work that we've been doing over the last couple of years to be prepared for geopolitical risk upsets in the supply chain looks to be paying off as we now encounter these tariff uncertainties. And so we've mentioned before, and Greg might want to have some comments too, on, we're sort of fairly well covered on OCTG for this year. And we've also thoroughly reviewed our supply chain for where are the other pinch points, whether it's pipes, valves, and fittings, or chips, or any of the pieces and parts that we utilize every day to make sure that we don't wind up into a sole supplier type dynamic and see a disruption or see a big tariff impact. But Greg, if you want to add anything, feel free. Yeah, thanks for the question. The team's done a really good job over the last several years of digging deep into our supply chains to make sure we had security of supply. That was our initial concern. We've traced all of our not only initial, but secondary supply chains of our providers all the way back to where the products are being manufactured and to guarantee security of supply. More recently, that then applies to making sure we can not only get what we need, but also get it at the right price and avoid potential tariffs. For this year, we've secured predominantly all of our tubulars that we're going to need for the year. Most of those are done domestically, but we've locked in pricing and then locked in supply. A lot of the other smaller items, we're working through making sure we've got access to those at fair prices as well. So as Brendan mentioned in a previous question, any tariffs or other volatility should be relatively minor as they flow through to our overall capital costs. Great. Really appreciate that color. Thank you. I'll turn it back. Thanks, Dennis. Thank you. At this time, we have completed the question-and-answer session, and I will turn the call back over to Mr. Verhaest. Thanks, Joanna. Thank you, everyone, for joining us this morning. Our call is now complete. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.