Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2025 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 one. 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 would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest. Thanks, Joanna, welcome everyone to our fourth quarter year-end 2025 conference call. This call is being webcast. 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'll 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 excited today to update the market on our latest results and the culmination of several years of strategic transformation at Ovintiv. With relentless focus and discipline, our team has remade our portfolio, reset our balance sheet, grown profitability, and built one of the deepest inventory positions in our industry. We have done all that while delivering superior returns on invested capital, both through the drill bit but also through smart transactions. All along, we've been guided by a very simple formula: superior and durable returns will accrue to the company that builds a deep inventory in the best resource, creates a competitive execution advantage through its culture and expertise, and has the discipline to allocate capital to the highest returns and get those returns on a full cycle basis all the way to the bottom line. Year to date, in 2026, we have closed the NuVista acquisition and reached an agreement to sell our Anadarko assets. This means our portfolio transformation is complete, and it leaves us with a very focused and high-quality portfolio in two of the best plays in North America, the Permian and the Montney. Proceeds from the Anadarko sale will go to the balance sheet, marking the achievement of our debt target and right-sizing our capital structure. The enhanced resilience of the business means that we can return more cash to shareholders, and the new shareholder return framework that we unveiled today does just that. Several years ago, we made the strategic decision to focus our portfolio and build high-quality inventory depth in the Permian and the Montney. Approximately 80% of the remaining sub $50 breakeven oil locations in North America are located in those two basins. Bolstering our positions in these plays, where we have competitive advantage, means we can continue to deliver durable returns for many years to come. Since 2023, we've increased our Permian and Montney drilling inventory by more than 3,200 locations at an average cost of $1.4 million per net 10,000 foot location, and we did it without diluting our shareholders or stressing our balance sheet. This inventory life expansion has been unmatched by our peers and leaves us with one of the most valuable inventory positions in the industry. Our sequencing between inventory additions and debt reduction was carefully managed. We recognized the importance of reducing debt, and we balanced that objective with timely transactions that our team generated to put our shareholders into premium inventory for the right price. This greatly extended our premium inventory duration. We have now cleared both of these hurdles, and that represents a material de-risking event for our shareholders. As North American shale continues to mature, a very clear competitive advantage is emerging for companies like ours that have already set their inventory position up for success, have a clean balance sheet and can access premium price markets, and have a demonstrated track record that translates to leading-edge efficiency and returns. That combination of attributes is truly differentiated. Following the close of the Anadarko sale, which we expect will happen early in the second quarter, our net debt will be roughly $3.6 billion. This brings our leverage more in line with our peer group and opens the door for us to allocate a greater portion of our free cash flow to shareholder returns. The chart on the left of slide 6 details the sources and uses of cash to get us to the $3.6 billion. If you'll recall, we funded the NuVista acquisition with a balanced mix of cash and equity. The cash component was largely funded by a term loan. With the proceeds from the Anadarko sale, we plan to first pay out the term loan and our 2028 notes and then allocate the rest to our credit facility and commercial paper balance. Our remaining long-term debt profile will have no maturities before 2030. We expect to realize $40 million of annualized interest savings from the repayment of the 2028 notes. This is in addition to the $25 million of annual savings we will realize from paying out our 2026 notes earlier this year. We remain committed to our investment-grade credit rating, we expect the Anadarko sale and subsequent deleveraging to be credit positive. With the Anadarko sale set to close in early Q2, we are in a position to increase our shareholder returns. We continue to believe that our equity is significantly undervalued, share buybacks continue to screen as an attractive return on investment. Our new framework will allow us to be more opportunistic in addressing this valuation discount. In 2026, under the revised framework, we will plan to return at least 75% of our free cash flows to shareholders. Longer term, we have set the expected range from 50%-100%. This wider range is intended to allow flexibility to accommodate commodity price volatility and avoid pro-cyclical buybacks. To be clear, our 2026 buyback target will be based off our full-year free cash flow as we plan to make up for the pause that we had initially planned for this first quarter. We plan to commence buybacks immediately. In conjunction with our new framework, our board of directors has authorized a share buyback program totaling $3 billion. I'll now turn the call over to Corey to discuss our year-end results and 2026 guidance. Thanks, Brendan. Our 2025 results demonstrate another year of execution excellence and strong financial performance. Our full-year cash flow was $3.8 billion. We generated free cash flow of more than $1.6 billion, of which over $600 million was returned directly to our shareholders. Our focus on capital efficiency enabled us to produce more with less capital. Our initial guidance for 2025 had us delivering total volumes of 605,000 BOE per day for $2.2 billion of capital. Throughout the course of the year, we lowered our capital by $50 million and produced an additional 10,000 BOE per day of total volumes. Importantly, we also continued to make progress on debt reduction, ending the year with less than $5.2 billion of net debt, a decrease of more than $240 million. Our solid execution in 2025 has set us up for continued success in 2026. Our strong operational performance during the fourth quarter delivered oil and condensate volumes averaging approximately 209,000 bbl per day at the high end of our guidance range, and our capital investment of $465 million came in at the midpoint of our guidance. We also matched or beat our per-unit cost guide on every item, continuing to build on our track record as an industry-leading operator. Our fourth quarter cash flow per share at $3.81 beat consensus estimates by about 10%, and our free cash flow totaled $508 million. All in all, we delivered another strong quarter, both operationally and financially, which allowed us to enter 2026 with significant momentum. Maximizing capital efficiency and free cash flow remains a primary focus for our teams this year. We're executing an oil-directed maintenance or stay flat program with level-loaded activity in both the Permian and the Montney. The resulting oil and condensate run rates for each asset are roughly 120,000 barrels per day and about 85,000 barrels per day, respectively. Our 2026 program, including one quarter of Anadarko operations, will deliver 209,000 barrels per day of oil and condensate over 2 Bcf a day of natural gas and total production volumes of 620,000-645,000 BOE per day for about $2.3 billion of capital investment. When compared to the preliminary 2026 production outlook of 715,000 BOE per day we provided in November, the sale of the Anadarko reduces volumes by about 70,000 BOEs per day, and the timing of the NuVista acquisition closing reduces those volumes by about 10,000 BOEs per day. We expect to see margin improvement in 2026, driven by lower LOE, production and mineral taxes, and interest expense. Our T&P costs will increase this year as a result of greater Montney weighting in our portfolio, additional Montney processing capacity, and increased market access in both plays, which enhances our netbacks. In the first quarter, we expect production to average approximately 670,000 BOEs per day, including about 223,000 barrels per day of oil and condensate. This will be the high point for the year. This includes roughly 3,000 or 4,000 BOE per day of cold weather impacts that we experienced across the U.S. assets in January. Our capital spend will also be the highest in the first quarter at about $625 million, largely due to $50 million of capital allocated to the Anadarko and some drilling activity in the Montney that we inherited from NuVista. I'll now turn the call over to Greg, who will speak to our operational highlights. Thanks, Corey. Let's dig into each of our two asset-level development programs. Starting in the Permian, capital efficiency and free cash generation remain the top priorities as we work to drive efficiency in every aspect of our operation. 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 2025 Order of Merit for Midland Basin Performance. Ovintiv had the highest three-month cumulative oil per foot again in 2025 and was the only operator who improved performance in each of the last three years. There are several factors that have contributed to our type curve improvement over that period of time, and one of the bigger factors has been our use of surfactants in our completion designs. We have been studying surfactants for a number of years, both in the lab and in the field. We pumped them in about 300 Permian wells since 2019. Compared to a similar group of analog or non-surfactant test treated wells, we see a 9% improvement in oil productivity. We believe surfactants account for roughly half of the type curve improvement we've observed in our Permian assets since 2022. We tested different chemical formulas across our acreage. Although performance varies by zone and by county, there is meaningful oil recovery benefit from these low-cost additives, which are highly economic. We will continue to hone our approach and trial different products across the acreage. We are very pleased with the results we've achieved so far. Our Permian team continues to set the efficient frontier when it comes to drilling and completions performance. On completions, part of our success is from utilizing our real-time frac optimization. Every job we pump is optimized in real time using proprietary algorithms, leveraging our vast private Permian data set. This also allows us to make real-time decisions which improve well recovery and reduce costs, leading to better pad economics. We also made efficiency gains this year through use of continuous pumping. We pumped for 7 straight days on our first trial, leading to a 20% improvement in completed feet per day. Our full year average completed feet per day was about 4,250. This was more than 10% faster than our 2024 program average. On the drilling front, we have developed several in-house AI tools which have allowed us to reduce cycle times, minimize failures, and accelerate efficiency gains. Our 2025 drilling speed averaged more than 2,000 ft per day for the second consecutive year. Our pacesetter well was over 3,000 ft per day, so we'll look to continue improving on what we believe are basin-leading results. These cycle time improvements are driving lower well costs. Our 2026 expected drilling and completion cost is among the best in the industry, at less than $600 per foot, which is about $25 per foot lower than last year. The 136 net wells we brought online in the Permian in 2025 continue to meet or slightly exceed our 2025 type curve. This type curve was unchanged across the year, and it remains unchanged in 2026. This year, we plan to run a low-level program with five rigs and one to two frac crews to bring on about 130 net wells. We plan to hold oil and condensate production at roughly 120,000 bbl per day. While our Permian economics are driven by oil, it's important to note that we now have about 150 million cubic feet per day of firm transport, leaving the basin for our Permian natural gas volumes. This means that roughly 55% of our 2026 gas production will be priced at the Gulf Coast instead of Waha. Last year, our unhedged Permian gas price realization averaged $1.55 per Mcf, about 179% of Waha. Moving north to the Montney, we remain very pleased with the tremendous depth and quality we have added to our acreage in the heart of the Alberta oil window over the last year. We are very excited to have the NuVista assets in our portfolio, and we are already working to integrate them into our business as safely and efficiently as possible. As a reminder, we plan to deliver well cost savings of $1 million per well across the acquired assets through the application of our industry-leading approach to drilling, completion, and production operations. We demonstrated our ability to capture similar cost synergies last year as we integrated the Paramount assets into our business. The swift achievement of those synergies is a real testament to the culture and capability of our Montney team. We couldn't be more pleased with how those assets have performed. We quickly achieved our well cost savings target of $1.5 million per well, took 14 days out of the drilling cycle time, successfully tested the upside potential of the asset with a higher density development. At our 15 of 16 pad, we added a third bench and increased density to 14 wells per section, we're seeing initial productivity rates that are exceeding our expectations. These results have unlocked roughly 130 upside locations across our Montney acreage. This year, we plan to run 6 rigs and 1 to 2 frac spreads to bring on about 135 net turn-in-lines. We plan to focus roughly a third of our activity on the newly acquired NuVista acreage, a third on the legacy Paramount lands, a third will be split between our legacy Pipestone and Cutbank Ridge areas. Current production from the Montney is in line with our previously communicated run rate of about 85,000 bbl per day of oil and condensate. We are maintaining a repeatable type curve. Although individual wells in the play will display a range of oil mix, the aggregated program delivers very predictable results. Due to some planned plant turnarounds, Montney production in the second quarter is expected to be at the lower end of our full year guidance range of 83,000-87,000 bbl per day and 1.75-1.85 Bcf per day of natural gas. We are working with our midstream providers to minimize the downtime as much as possible. In 2026, we expect our D&C cost to average less than $500 per foot. This is about $25 per foot less than our 2025 well cost. Part of the decrease year-over-year is thanks to faster cycle times, as well as greater use of domestic sand in our 2026 completions. Roughly half of our 2026 Montney wells will be completed with locally sourced sand. Overall, the asset is performing very well, and the low-cost, high-productivity nature of the wells has meant we've consistently been able to generate highly competitive economics from the play throughout the commodity price cycle. I'll now turn the call back to Brendan. Thanks, Greg. Over the last few years, we've worked hard to high-grade and focus our portfolio, build extensive inventory depth, drive profitability, and reduce our leverage. Over that time, our team has delivered outstanding results. Those results demonstrate that our strategy is working, and our execution excellence is translating into increased value for our shareholders. We've been very intentional about building a high quality business. We've demonstrated along the way that we are disciplined stewards of our shareholders' capital. We will continue to be relentless about making our business more profitable and more valuable every day. We've reached a new period of stability, and we are excited to unlock the full value of what we've built. This concludes our prepared remarks. Operator, we're now ready to turn the line back for questions. Thank you. Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing star one. We will now begin the question and answer session and go to the first caller. First question comes from Arun Jayaram at JP Morgan. Please go ahead. Yeah, good morning, Brendan and team. I was wondering if you could maybe elaborate on the change to your shareholder returns program in 2026, where you're increasing the mix to 75% from 50%. Thoughts, Brendan, how we should think about the mix of shareholder returns post 2026 relative to the 50%-100% long term range? Thanks, Arun. Good morning. Today we see a lot of value in our equity, and when we close the Anadarko, we expect to be at about $3.6 billion of debt. That's really the reason for shifting to the upper end of the range this year. Longer term, we've set a wider range. Really, the thinking here is, you know, we want this framework to be durable through the commodity price cycle, and in particular, we want to avoid setting up a procyclical framework. What I mean by that is, when commodity prices are high, you probably should expect us to be more towards the low end of that 50%-100% range. That, what that allows us to do is, you know, be banking that windfall, if you will, when commodity prices are well above mid-cycle, be banking that windfall permanently into the capital structure. Then on the flip side, in periods of lower commodity prices, you know, below the mid-cycle level, that could push us to the higher end of the range, where we're likely to see more valuable, more value in the equity. That's the only thinking behind the longer term, 50-100 range, and we'll have the ability to flex around that. You know, when we see value like we do in the equity today, then the upper end of the range is appealing. Great. Brendan, my follow-up, we were, you know, very interested in the surfactant program, perhaps we're surprised that you guys have been doing it for so long. I was wondering if you could maybe unpack some of the details on the program, which looks to be driving some productivity gains versus control wells. It looks like you're using surfactants more on the completion end or the front end of the well lifecycle. Maybe talk about the cost benefit wondering if you have tested surfactants in terms of moderating your base declines, as a couple of your peers have highlighted thus far. No, love the question, Arun. There's a lot going on in the company today, glad you dug in on that surfactant piece. I'll maybe just set up a couple of comments here and then kick it over to Greg on the details. You know, this is just another example of the stacked innovation that we've been talking about. You know, really, for a few years now, we've been emphasizing three key features in our completion design that we think are adding value, adding to our type curves, and we've been calling it fluid chemistry. We were kind of deliberately trying to keep it quiet on exactly what we were doing since we felt like we had kind of gotten out ahead of others in this space. That's what you're seeing us show off today with 300 results already. That's, you know, really helped us push us to the top of the leaderboard on Permian productivity. That's kind of a bit of the background, and, you know, but I'll kick it to Greg here to talk about some of the specifics. Yeah. Thanks, Brendan, and thanks, Arun, for the question. Yes, you highlighted it correctly. We are focusing our surfactant program on the initial completions. This is something we've been working on for a number of years, and the team continues to make breakthroughs and build our confidence in this space. Maybe just a little bit about what we're doing. These surfactants that we're pumping, they're liquid additives that we include in our frack fluid, that are designed to improve oil recovery from the reservoir downhole. Once you pump them downhole, they change the surface tension of the fluids, which allows more of the oil to be released from the rock, flow into the fracture and then out the wellbore, increasing recovery, not just in the short, but in the longer term, as we've demonstrated over the last several years. You know, we've been working for a number of years on this, both in the lab and in the field. We've done core testing in the labs, as well as field trials, to try to determine which surfactants work best in which zones. We've been working to optimize the concentrations that we pump, so the amount of surfactant per ratio of fluid, both to optimize the effectiveness but also optimize the cost of these surfactants. So far, you know, we pumped, as we said in the prepared remarks, surfactants in around 300 wells, generating that 9% uplift, but that's been a progression over time. We started out in the early years with some field trials, gained confidence, and more recently, last year, we pumped surfactants, and about 75% of the completions we pumped in the Midland Basin and saw very good results with that. We would anticipate pumping a similar amount this year in 2026. Been very pleased with the results on our completions. We've also tested it to some degree in producing wells. Haven't seen quite the effectiveness there, and so that is a very small part of the program. The team continues to experiment with this and will continue going forward. We do believe it's a very effective way to improve recovery in the near and long term from these wells, and we think it has been and will continue to be a big reason for our outperformance in the Permian. Great. Thanks a lot. Thanks, Ben. Thank you. The next question comes from Lloyd Byrne with Jefferies. Please go ahead. Hey, good morning, guys. Congrats on the transformation. I know it's been a long process. Maybe I wanted to ask about the surfactants a little bit as well, and maybe Greg can talk about a little bit about costs per well, and how are you seeing that go forward? I know you're just in the early stages, but if you have 9% improvement, are the costs going up as well? Hey, Lloyd. Yeah, we, you know, this is an interesting question. When we first started this work several years ago, there was some really, you know, expensive chemistry out there that was a real barrier to pumping it more broadly just because of the risk-reward feature. What our lab work has really let us do is trial, you know, hundreds and hundreds of different chemistries here, which allows us to then create substitutes that have now kind of almost completely displaced some of those original chemistries that were in the market several years ago. Greg commented on, you know, one of the things we've been fine-tuning is the amount of surfactant that we've been pumping. The other feature has been substituting, you know, cheaper and cheaper alternatives. We've been a little reluctant to be specific about some of this here because we're trying to protect what we think is an advantage, but, you know, it's in the hundreds of thousands of dollars a well, is a probably a good way to think about it. Okay, thanks. Just as a follow-up, you've kind of moved from four basins to two basins, what kind of opportunity does that give you to cut costs, maybe from a organizational structure as well? Yeah. You know, really appreciate that, Lloyd. You know, with this latest transaction, what we've pointed to is $100 million of synergies, but we also pointed to several, you know, synergies that we didn't quantify at this time. You know, we think those are gonna show up on the infrastructure side. We saw that with the Paramount integration. Really now we're kind of stitching together our legacy infrastructure, the Paramount infrastructure, and then now the NuVista infrastructure. All three of those overlap, there's gonna be some of those synergies realized, and we look forward to updating the market on those as we get deeper into the year. Then there's gonna be some organizational synergy here, too. You know, everyone on our team has done a tremendous job working safely through a lot of change at our company, and created a lot of shareholder value, and so I do want to recognize their effort and the results that they have delivered. We've taken big steps to simplify the portfolio, and so we will be redesigning our organization to match that new portfolio. We expect to have those changes completed shortly after the Anadarko divestiture, and we'll update the market on the impact of those, you know, once we get there. Great. Congratulations again. Thanks, Lloyd. Thank you. The next question comes from Neal Dingmann with William Blair. Please go ahead. Morning, guys. Nice quarter. Brendan, my question is just on the Montney. I'm just wondering, looking at the activity, looking like maybe, am I right, about a third of activity coming from the NuVista, one third Paramount, and then the one third, the prior position. I'm just wondering, if so, do you anticipate sort of similar activity across the board like that? You know, are those well results pretty similar across the board? Yeah, Neal, you got it nailed. That's about the activity cadence going forward is gonna be that one third, one third, one third. Just a quick comment on the driver for that. That's really an outcome of our reoccupation strategy. Folks will remember that's the strategy we pursue both in the Permian and the Montney to maximize value from our acreage as we manage the interactions between cubes. You know, a lot has been made over the last several years about the interwell effect of co-development or cube development, but there is also intercube effect as we drill a new cube beside an existing cube. That is a governing feature of our development programs. That, in no small part, drives that allocation of activity as we just continue to mow the yard, across our acreage position in both the Montney and the Permian. That's the big driver of that piece there. That makes sense. Maybe just a second one on that, on that same vein for you, either you or Greg, just maybe more in the Permian development. Can I assume that the development will continue to consist mostly exclusively of cube development? If so, you know, is well spacing staying relatively the same there, or is there any changes? Yeah. Thanks for the question, Neil. In the Permian, we continue to optimize and make small tweaks over time to our well spacing to account for, you know, the existing cubes or parent wells in an area. Overall, we're still using the same approach. We complete the entire cube at the same time, come back 18 months later and complete the offset cube, getting, you know, all of the zones at the same time at a fairly similar spacing. That's allowing us to get very consistent results year-over-year. We're not saving any, you know, lesser zones to come back later when they would be disadvantaged. We're getting the whole cube at the same time, and that's working quite well for us. No major changes there. Good to hear. Thanks, Greg. Thanks, Neil. Thank you. The next question comes from Neil Mehta with Goldman Sachs. Please go ahead. Yeah, thanks so much, and Brendan, congratulations on again, this transformation over the last five years, and maybe that's kind of the key question for me, which is: Have you gotten the portfolio to the optimal level where I think when you took over, you were in six areas, now you're at two. Are you in your sweet spot? Does that mean that, you know, there's a pause on M&A as you digest all this, and the incremental dollar really is to the buyback, or is there another leg to the story that you're still exploring? Thanks, Neil. The portfolio transition here is complete. We've clearly planted our flag in the Montney in the Permian, where we have competitive advantage and where we see the best resource. We've built one of the longest duration inventory positions while we did that. We really believe that stability has real value for our investors, and we look forward to continuing to unlock the full value from what we built. Okay, appreciate that. Just a follow-up is, just on the shape of both production and CapEx through the year. I guess Q1's a little bit heavier, but that's, I'm guessing that's part of that's just the pro forma portfolio. Q2, you've got a little bit more maintenance in mind. Can you just talk about how you're thinking about the cadence for production, quarterly cadence of production and then capital through the year? Yeah, great. You nailed it exactly, Neal. The little bit higher capital in Q1 is absolutely just the Anadarko effect. Once we close that'll come out, and we'll just run rate out. You know, I think we've probably said transition or transformation the highest word count of this call so far, but one of the other pieces that we've transformed is the load-level nature of our programs, and that has been, you know, over multiple years here to shift to a fully load-leveled program. Really, we've got that as a really key feature in 2026. We really like how we've leveled out that, and it just creates more predictable and stable business to operate within. Thanks, Brendan. Yeah. Thanks, Neil. Thank you. The next question comes from Greg Pardy with RBC Capital Markets. Please go ahead. Yeah, thanks. Good morning. I had a really couple of technical questions. I was curious, just first, how much of an opportunity is there with respect to this using in-basin sand? I caught some of Greg's comments or Brendan, your comments, but I'm just wondering, has that been perhaps optimized in both the Montney and the Permian? Yeah, love the question, Greg. Yeah, we're really excited about the in-basin sand results that we're already delivering in the Permian and really excited about the evolution that's going on in the Montney as we shift more and more to domestic and wet sand in the Montney, too. This is another great example of stacked innovation, you know, creating value for us and also a great example of knowledge transfer and value between the two pieces of our portfolio, because this is obviously something that we led the charge on in the Permian and now are leading the charge on in Canada and in the Montney. You know, maybe, Greg, if you wanna give a few comments around the percentage of utilization and where we're headed there. Yeah. Thanks, Brendan. Yeah, Greg, so on the Permian side, you know, we've been at local wet sand for a number of years, and essentially 100% of our program is gonna be local wet sand from mines there in the field. We're continuing to refine that process with our sand pile and our delivery systems, but that's a very fairly mature program. The new news over the last year or so is moving some of that technology north of the border. As you know, historically, most operators will be taking Northern White sand by rail from the U.S. up to Canada, and that just adds a whole lot of cost. We've been working with providers there to use more local domestic sand. The sources aren't quite as close to the field, there are good sand sources. This year, we're gonna have roughly 50% of our sand pumped will be domestic sand there, sourced in Canada. You eliminate that rail charge, and you're able to lower cost dramatically. We've also begun testing wet sand in Canada, and it works quite well. This time of year, we joke it's a little crunchier, but it still goes down whole, just the same. That is an evolving technology that we think we're gonna be able to use more and more over time. We should see some of the same efficiencies we saw in the Permian and some of the cost reduction, but a little more nascent in Canada than it is in the Permian, but still working quite well. Okay. Thanks for that. Then I'll maybe just kind of stay with Montney now. When you kind of compare and contrast NuVista versus the Paramount acquisitions, how do you look at perhaps the degree of low-hanging fruit, cost synergies, efficiencies, and things like that? I think, Brendan, as you've mentioned, NuVista was actually a pretty good operator, but I'm just curious on the two. Yeah, I think, I mean, I'll start with geography first and then Greg will have some comments on the integration. The NuVista piece really fills in the jigsaw puzzle. With Paramount, we stepped further south than we had been with our legacy, not by a long ways. And we were, I think, you know, had the right amount of humility there to make sure when we integrated those assets, that we didn't change something inadvertently and create risk in the integration. We stepped our way in a very thoughtful integration process through, you know, really a full year here. One of the highlights in the deck today. Again, there's a lot in there, but one of the highlights in there is pointing to the really strong results we're seeing from our first density pad, and we're excited about those. Then with, in contrast, you know, NuVista really filling in the jigsaw piece in between. We, you know, we just have a lot more technical confidence, and we're kind of integrating quite quickly there with that piece. You know, Greg, if you want to comment on some of the specifics about how it's going. Yeah, for sure. I think Brendan set it up really well. It's going to be the same process on NuVista as it was on Paramount. It's just going to go a little faster because of our familiarity with the assets, plus all of the learnings we had on the Paramount integration. We're going to try to accelerate things a little, and we think that that's very, you know, very doable. The team's already hard at work, you know, employing the same playbook that we've used on all the last transactions. We came in day one, took over the asset. We had a short safety orientation and then got to work. By that afternoon, we were operating the asset as Ovintiv. You know, it's only been a few short weeks, but we've already connected all the producing wells to our Operations Control Center so that we can optimize production and minimize downtime. We've linked the drilling rigs to our DRIVE center, which is our optimization tool, where we use AI to help optimize drilling performance. That's gonna allow us to deliver our synergies here very quickly. We've already incorporated the $1 million in per well of savings. The synergy savings are what you're seeing as part of the guidance. We're gonna be delivering that from day one. So far, we've had really good results. The teams are integrating well. The new wells are being drilled as expected. As I mentioned earlier, production's already at 85,000 bbl a day, which is what we expected for the assets as they come together. Integration is going quite well. Just really, really pleased, and I think it'll be very similar to last time. It'll just go a little faster and hopefully be even more effective. Greg, that high density test results on slide 14 there, which was the 14 wells per section that we talked about when we started out with the transition of the Paramount, integration of the Paramount assets. That does move 130 wells out of upside into the premium bucket for us. A really critical result. Terrific. Yeah. Thanks for the rundown and congrats on the transformation. Thank you, Greg. Thank you. The next question comes from Josh Silverstein at UBS. Please go ahead. Hey, thanks. Good morning, guys. you know, from a balancing perspective performer, you're now below that $4 billion long-term target that you've had for a while now. How should we think about the right level of debt for you guys going forward? Should we think about it as kind of an absolute level or net debt level to kind about free cash flow allocation? Thanks. Yeah. Hey, Josh. We've, we've reached that target. In fact, we're gonna move past it here with the Anadarko proceeds. You know, really, we're not setting a new target here. If you, if you remember, the $4 billion net target that we set was really a trigger for increased shareholder returns, and we spent obviously a lot of time and effort getting us to this spot. You know, that is now happening. That trigger is pulled, and the catalyst to change those returns is gonna be up and running right after we get off this call, I guess. You know, we've had to balance that debt reduction as part of our capital allocation for a long time. We've now put ourselves into this resilient position. At the same time, we put the inventory into a really strong and resilient position as well. It just means we're in a place here now we can focus on keeping the debt, you know, around this level and focus on allocating more to cash returns. That's how we're thinking about the debt level go forward. Got it. From a money operating perspective, I know you guys, on the Paramount transaction, were able to kind of optimize the infrastructure a bit more. Can you talk about what you might be able to do on the NuVista asset as well to go and, you know, kind of improve the overall productivity here? Maybe from a long-term planning perspective, is there anything you guys are thinking about from an infrastructure standpoint that you may need to invest in or want from a third-party build? Thanks. Yeah, I'll turn it over to Greg here, but, you know, we are excited about taking these sort of three disparate systems that were previously all operated independently and being able to have one, you know, value-creating mindset over all three of them. You know, Greg, you can comment. Yeah. Thanks for the question. In the short term, we're really focused on, you know, getting the well cost savings at the well level, putting in our completion designs, our facilities designs, and that's gonna take place over here, like, immediately over the coming months. Longer term, though, we're really excited about the opportunity to optimize infrastructure. If you look at the map, it's just reeks of opportunity. When you look at how well the three positions come together, the gas plants, how close they are to each other, the number of midstream lines that are crossing the asset. A little more work to do there. It's a little more time-consuming to work with the midstreamers to make sure we're doing the most efficient operations there. Over time, that's something we're gonna target to get our T&P down, to get the gas molecules to the most efficient plant, and to work through those things. That's coming a little longer. In the short term, we're really excited about the well cost savings. Longer term, we think the midstream, there's a lot of opportunity there, and that'll be something we'll start working on here immediately. Great. Thanks, guys. Thanks, Josh. Thank you. The next question comes from Doug Leggate with Wolfe Research. Please go ahead. Good morning, everybody. Brendan, I wonder if I could ask you about asset duration and how you define that. The portfolio repositioning is been extraordinary as everybody's observed, I'm trying to understand, when I asked this question to Diamondback earlier this morning as well, is this idea between sustaining production or drilling depth versus sustaining free cash flow? How do you think about that in the portfolio? What are you trying to solve for? Yeah, I mean, we haven't been exotic with our thinking there. We just run it off of what it takes to sustain the production. you know, in a lot of ways, what we've been talking about, Doug, is the ability to sustain the returns that we're generating today while we do that, production maintenance level. you know, this, again, I, at the risk of being too pedantic with it, this is why the reoccupation strategy and how we've approached both cube development, but also program design, you know, really de-risks our inventory duration over time. Just as a refresher here, because we're designing our annual programs with that reoccupation in mind, to come back to the 12, sorry, 18-24 months after we've drilled the prior cubes, because that's been the dominant feature of our program design, we essentially are sampling all of our remaining inventory with a full-year development program, either in the Permian or the Montney. What that means is we already know what the remaining duration inventory and how it's going to perform because we're drilling it today. We're not saving, you know, the worst locations for, you know, a decade from now. We're kind of drilling the full cubes. Right. Reoccupying cubes as we go. I believe that to be a big de-risker. You know, one of the other things that's important on this front is if we were telling you that that was what we were doing and we were delivering mediocre results, I think that would be up for question. We're delivering leading results while we're doing that, and I think that's the true differentiation. I appreciate that answer. I know it's a bit nuanced more than anything else, but forgive me for my second one, but you probably know I'm gonna talk about capital structure and all that stuff. I want to ask you about the your philosophical view as a CEO about your commitment to cash returns. Because if I play back to you what you just said today, you do not want to be guilty of procyclical buybacks, but that's exactly what you're doing in 2026, if I may say so. Meaning that your stock's up 25%, ExxonMobil's up 22%, oil's above $70 for reasons we all know are not necessarily fundamental. This is the year you're going for a 75% of your free cash flow per share buyback. Why are you not choosing to be more discretionary in your timing? I'm gonna try and not be, I guess I'm gonna still try and be humble here. 30% still doesn't get us to what we think is a reasonable valuation for the stock. I'm not trying to say that that's not great. We're pleased, obviously, with the momentum. We still see a lot of intrinsic value in the equity today. You know, when we talk about trying to avoid being procyclical, a lot of that is gonna be tied, as you know, Doug, to the commodity environment. Today we're not in a commodity environment that screams, you know, really high, you know, windfall situation. I think we're still in a relatively modest commodity environment today, and so we do not see the risk of being at 75% as a procyclical risk today because of that intrinsic value gap we still see in the equity. All right. I wanted to take the question. Thanks so much. Yeah, thanks, Doug. Thank you. The next question comes from Kalei Akamine with Bank of America. Please go ahead. Hey, good morning, guys. My question is on the 15, 16 pads. Maybe this is for Greg. Greg, wondering if you can talk about how you sequence the completions of the three zones and sharing the details on the frac job. That third zone has been an opportunity in the area, and it sounds like you guys have cracked the code. Where in the basin next do you plan to apply that design? Could the balance of the upside locations move into the de-risked inventory count this year? Yeah, I'll turn that to Greg. Thanks, Kelly. Sorry, I had trouble turning my mic on. Yeah, I appreciate the question. You know, we're really pleased with the results there on this, the 15 and 16 pad down in Carr. What the team has done there, just as a reminder, you know, when we acquired the asset, our base case was 12 wells a section. We said we'd have upside up to 16 wells. This is the first pad that we really got to design end to end in the area, and so we kind of met in the middle with 14 wells per section spacing. We added that third zone down in the lower Montney or the Sexsmith, some call it, and also increased density in the upper part of the cube. pumped a fairly normal frac design for us, which might be a little more intensity than some of the peers are pumping in the area, but it's a fairly normal frac design. It was really the stacking and spacing that we leaned in on, so far we're really pleased. The pad's been online a little over 100 days. The lower zones actually exceeding expectations of what we were expecting, the upper zones are holding up very nicely despite the increased density. Our plans now are to move to other parts there of Carr and employ this density test or, sorry, density design now. And that's why we've talked about 130 of the, call it, roughly 600 upside locations between the two deals. This, this proves up, you know, 130 of those. The next step will be to go to other parts of Carr and testing the third zone, and then we've still got work to do up in Wapiti and then, and other parts of the acreage. We'll be systematic about this. One pad doesn't prove up all the upside, but we'll continue to execute, you know, with this design on our future pads and then maybe even lean in a little more. We still have a little more upside, potentially up to 16 wells per section on a few of the pads. Really pleased, but wanted to wait until we had a few months under our belt before we talked about this one, and right now, we're feeling really good about it. Thanks for that detail, Greg. Maybe staying with the Montney here. The second question is on the plant turnarounds in 2Q. We understand that was elected by the midstream operator. How should we be thinking about the cadence of turnaround activity in the Montney? Is it annual? How much heads-up does the operator typically give you that a turnaround is needed? Should we expect better performance from these plants, and maybe that's in yield after this work has been completed? No, I appreciate the question, Kalei. This is fairly normal operations from the midstream processing plants up in Canada. They're on schedules that every two to three years, you take down the plant for a few weeks to do inspections, routine maintenance, maybe upgrade a few of the vessels. These are the kind of things that we're usually we know about well in advance. That's why we're talking to you now about something that's gonna happen next quarter. What, what we're experiencing this coming quarter, is we just happen to have five of them, which are all lined up at the same time. Normally, we don't really have to talk much about these because you may have one or two turnarounds going on at the same time, and you can move volumes around. When you end up having five at once, all lining up at the same time, it just takes a little more coordination. We're working with the midstreamers to try to minimize the amount of time that they're down, try to move volumes around them where we can. Right now we do feel like there will be some impact, and that's why we're guiding to be at the lower end of that 83,000-87,000 bbl per day in the Montney. This is something that I'd say it's fairly infrequent, that they all line up in the same quarter. Usually, they're more spread out over time, and they're more manageable. I don't think this is a longer-term risk for us. This is just something, the way the stars lined, we wanted to let everyone know that this was coming and that we're planning for it, so that when we come back and report Q2 earnings, there's no surprises. Just trying to give you guys a heads-up, but trust that we're working to try to minimize the impact as much as we can. Greg, just to follow up. Coming out of maintenance, could there be any increase in the performance in those plants, maybe that's in yield, after that work is done? You know, that's gonna vary by facility and exactly what kind of work they're doing, but usually these are not upgrades that add capacity. These are more routine maintenance. Think of it changing the oil in your car. It probably isn't gonna run a whole lot better after you're done, but in some cases, you know, we could see some minor improvement or flush production. For the most part, this is just routine maintenance, routine work that they're doing. Thank you, Greg. Thanks, Kalei. Thank you. The next question comes from Betty Jiang at Barclays. Please go ahead. Good morning. Congrats again on the portfolio transformation and leaning into the buyback. My first question on the Permian, if you don't mind me digging into the numbers a bit, but your lateral length is higher year-over-year, and so on a total net tail footage basis, it's almost up high single digits year-over-year. But holding production flat, even though type curve is unchanged, when we would typically expect some upside to that production. Could you just unpack the dynamic there? If we hold that Permian production flat, where could the CapEx trend on the normalized basis going forward? This is great, Betty, and I'll turn it to Greg here. The headline here is, we are seeing an efficiency gain on the well cost side, about 5% down on the well cost year-over-year, and then holding the type curves flat. What you'll see over time is that this is going to translate through into the total program, but there's some timing effects for 2025 or 2026 that are kind of masking that a bit here, but Greg can cover that. Yeah. Yeah, Betty, thanks for the question, as we've been talking about today, you know, we really like to usually run our programs on a very level-loaded basis. At least that's been our goal. We try to complete our wells as soon as they're drilled, so we don't carry excessive DUCs. As you might recall, last year we had a number of extra DUCs coming into the year. In the first quarter of 2025, we employed a spot frac crew in the Permian and came in and finished out all of those DUCs, which it had a couple of impacts to our program. One, capital was actually artificially low last year because for all of those DUCs, the drilling capital was in the previous year, we only saw the completion capital last year. The other result was we actually saw a really nice production boost there in the first quarter. We brought on over 50 wells in the first quarter, which was about double our run rate for the other quarters in the year. Really positive for last year. Unfortunately, for, you know, the metrics, we don't have that same circumstance this year, we do have a very level-loaded program that we're very, very good about. Allows us to become more efficient and continue to execute very repeatably when we do the same number of completions, same amount of capital, same production every quarter. If you think about the building blocks of the, of the guide, slightly lower cost per foot, same type curve. Really the only difference is the timing, and that's what you're seeing manifest as it rolls through the numbers. Over time, we feel like this is gonna be a very efficient program that's gonna continue to get better over time as we continue to drive down the costs and keep that type curve flat. Thank you for the clarification there. My follow-up is on the Montney surfactant use. I mean, it seems a lot of operational efficiency tailwind in Montney, but specifically, are you testing the surfactants in Montney as well? Is there any read across and viability there? I think I'll set Greg up here, but the, what we found and understood really from the early days of this is every bench in each county are gonna perform a little bit differently, depending on the wettability and the fluids that we're trying to impact. The Montney does have a wholly different down subsurface regime from temperature and pressure perspective, so it's gonna have its own bespoke completion optimizations. Some of that might be surfactants, some of it is looking like other pieces that can add to the performance that we're seeing there. It'll be a little bit different. We're quite a ways further advanced on surfactants in the Permian, you know, with 300 wells pumped there. We've done nowhere near that many in the Montney to this point. Really excited about completion design in the Montney. Generally, you know, we'll see surfactants, we're gonna go a little slower there just because of the temperature and pressure differences. Greg, over to you. Yeah. We're in our seventh year of surfactants in the Permian, we've learned a lot over that time. We've learned where they work best, what concentrations work best, as Brendan said earlier, which chemicals are most effective for the lowest cost. We've really advanced our learnings there. We're still in the early innings up in the Montney. The team does a great job, though, of sharing learnings cross-border and cross-asset. We're absolutely looking at things up there, and we've done some of the rock work, and we've done a few trials so far, I think, I would position it more as we're just getting started up there. The whole toolbox is available to us as we see that working, as well as we see higher completion intensity, stacking and spacing optimizations. All the things that we do in the Permian, we do the same in the Montney, and so we'll share those learnings cross-border, but maybe just a little earlier stage in the Montney on surfactants. It will be a slightly different setup just because of the pressure regime downhole and the rock fabric. It's just a different reservoir. We'll work to see if we can make the same kind of improvements there that we've seen in the Permian. Great. Sounds good. Thank you. Thanks, Betty. Thank you. The next question comes from Phillip Jungwirth at BMO Capital Markets. Please go ahead. Yeah, thanks. Good morning. Just with some of the industry news today, can you talk about how you see the prospectivity for the Barnett, Woodford across your Midland acreage and where that might be across north, south, and any plans to test this? Yeah, I'll turn this to Greg, but really pleased with the job the team's done here to assemble a position in the Barnett. Greg, over to you. Yeah, we've been very interested in the Barnett and been watching it for some time. I do think this is one of those plays that we're wise to learn from our peers and see what. The two things that are going on with the Barnett, it's a deeper zone, so it's got more pressure, and it looks like it's got good productivity, but it's also got higher costs. We're watching as some of our peers are de-risking the cost side, as well as de-risking the well performance. We do have a meaningful Barnett position. We've got Barnett rights on about half of our acreage position in the Permian, around 100,000 acres. We'll look to test that this year with our first well, so we'll get some information of our own, but we're also gonna watch and I think be prudent, on, you know, how much we lean into the Barnett. It's a deeper horizon that's separate from our cube, so that resource is still gonna be there later. It's not gonna be impacted by the shallow production. I think this is one where we have time to be a little more patient, but also have the ability to be a fast follower and go execute on that 100,000 acres if we choose to do so. Okay, great. Can you talk about what you've seen with LNG Canada ramping up the second train, starting up just as it relates to the AECO market, in event of supplying that versus maybe incremental equity volumes for the partners? More hypothetical, but would changes in ownership across the facility have any implications for Ovintiv or open up any strategic partnership or marketing opportunities? I think we are pleased in recent weeks to see that facility ramp up to essentially full capacity, which is kind of really the first time since the startup that it's been at that level. It's been a slow grind upwards with a bit of ups and downs along the way, as I'm sure you've followed. I think our caution on AECO remains, you know, the total takeaway from LNG Canada, while it's great to see it, you know, in recent time up to that level, it is still, you know, relatively small relative to the total productivity potential of the basin. We've seen the sort of behind pipe volumes, if you will, able to fulfill that takeaway. Still cautious, AECO, still strong believers in diversifying our Canadian gas portfolio into alternate markets, which is, I think, kind of part B of your question there. Yeah, we continue to be interested in building out a diverse portfolio of markets for our downstream gas and, you know, further LNG exposure is going to probably be part of that over time. We've now added that to our portfolio, and we're excited to have those positions in place. I would expect over time, we will probably grow that exposure. Thanks. Yeah. Thank you. Thank you. The next question comes from Kevin MacCurdy with Pickering Energy Partners. Please go ahead. Hey, good morning. You guys have laid out a solid maintenance program with a big buyback for this year, but I wanted to revisit the growth question. You've talked about the potential to grow the Montney by 5% a year, and now that the portfolio transformation is about to be complete, debt is being reduced, and you have oil in the mid-$60s, how does that growth opportunity stack up in your capital allocation framework, and what could change that rank? Yeah. No, appreciate it, Kevin. I think the two things that we've talked about with respect to growth are still very much in place. The two gates, if you will, are, do we see a fundamental call for incremental barrels or BTUs? Again, we don't see that today. The market's not begging for companies like ours to bring more volumes into the market. That's kind of gate number one. Then gate number two is, can we create more cash flow per share growth out of share buybacks or out of incremental rigs? Today, we see that equation tilted towards the buybacks. We get a better cash flow per share outcome across a range of commodity price assumptions going forward and share price assumptions going forward. We expect we get a better cash flow per share outcome out of buying the shares. The combination of both of those two gates today are telling us to stay in maintenance mode. I appreciate your question because it surfaces the other aspect of the portfolio transformation that's important here. Not only have we added tremendous inventory duration and focused the portfolio, we've also unlocked growth potential, and at some point in the future, those two gates will call for growth, and we've now created the capability to do that very efficiently at high return for our investors. I'll leave it there. Appreciate the answer. Thanks. Yeah. Thanks, Kevin. Thank you. The next question comes from Dennis Fong with CIBC World Markets. Please go ahead. Hi, good morning, thanks for taking my questions. My first one relates towards inventory to some degree. It's clear that you've done a lot of work around the ground game to add low cost, high quality, premium inventory. Can you kind of talk towards how that helps you kind of either gain comfort with existing depth as well as how that may influence allocating capital both north and south of the border? Which, from what looks kind of like a, from a well count perspective or a till perspective, almost a balanced program, north and south? You got it, Dennis. That ground game's been really effective for us. Obviously, a lot of focus on the larger transactions, the ground game has been grinding away very efficiently. You know, you think about where we've arrived at here, we've put the transaction risk of having to build inventory duration behind us, now we can, you know, rely on that ground game, which is very efficient, low cost way to sustain our inventory duration. It just is sort of funded, you know, within our framework, within the balance sheet that we've got today. We can just sort of put that in and let it opportunistically tick away as we go along here and sustain the inventory depth that we've created. We like that feature and, you know, really proud of the team for how it's been able to do that over time. As far as the capital allocation between the assets, today, we're really just holding both of those assets at that flat production level. The outcome is, like you said, a relatively balanced till north and south, but it's really more designed to hold the production flat. Great. Appreciate that. Shifting on to innovation, there's obviously a lot of questions today focused on obviously, the use of surfactant, and obviously, your teams have done a very good job in terms of applying kind of, leading-edge, technology on improving operations. I'm just curious, has there been anything that you guys have learned potentially from the NuVista teams and operations that they were doing, or techniques that they were running, that you believe could be applicable to your existing Montney base and, or even the Permian? Yeah, no, we love that question, Dennis. You know, really, one of our mantras here, is the only infinite rate of return we can generate is by learning from somebody else's capital. You know, what better way to do that than in an integration where you have full transparency and data and everything? I'll put that to Greg, because there are several things that we've been excited about from the NuVista team. Yeah, we were really pleased with the NuVista Energy transaction. You know, not only did we get some great assets, we've also got a number of really quality individuals that came over with the transaction and brought over some really good ideas. Out in the field, I think they've done a really good job on some of their gas lift designs and how they've optimized their gas lift techniques in the field. We're already working with them on how do we take some of those ideas and use them more broadly across our portfolio, incorporating with our Operations Control Center and really upping our game a little bit there on the gas lift. Which will have some application in the Permian, but definitely will have application across the Montney. Another place that we've talked with them a lot about is on landing zones, on the very precise, not which interval in the Montney, but, you know, to the meter or to the foot, where you're going to land the wells. They've got some really good ideas that they've been able to execute on some different landing zones that have allowed them to drill wells a little faster than we have in some cases. We're implementing that into our program, and we think that's gonna help us even improve quicker in Canada than we have been so far. Our teams are doing a really good job, but we're always open to learning from others. We try to approach competitor intelligence or integrations with, "What can you teach us?" Not, not, "What can we tell you we know?" So far, we're learning some from them, and it's going really well. We're really pleased with that. Thanks, Dennis. Thank you. At this time, we have completed the question and answer session, and we'll turn the call back over to Mr. Verhaest. Thanks, Joanna. Thank you, everyone, for joining us today. 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.