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. 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, and welcome, everyone, to our Fourth Quarter and Year-End 2025 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 disclosed 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 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 to build a deep inventory and 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 rightsizing 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 locations, 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 recognize 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 derisking 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 realized from paying out our 2026 notes earlier this year. We remain committed to our investment-grade credit rating, and we expect the Anadarko sale and subsequent deleveraging to be credit positive. With the Anadarko sales 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 and 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% to 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 continue 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 barrels 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 remain 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 to 645,000 BOE per day or 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 improvements 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 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 2025 Order of Merit for Midland Basin performance. Ovintiv had the highest 3-month cumulative oil per foot again in 2025, and was the only operator who improved performance in each of the last 3 years. There are several factors that have contributed to our type curve improvement over that period of time. One of the bigger factors has been our use of surfactants and our completion designs. We've been studying surfactants for a number of years, both in the lab and in the field, and 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, and 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, but 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. We take great pride in our development approach and our ability to stack multiple innovations together to create industry-leading results. On completions, part of our success is from utilizing our real-time frac optimization. Every job we pumped 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 feet per day for the second consecutive year. Our Pacesetter well was over 3,000 feet 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 load-level program with 5 rigs in 1 to 2 frac crews, bringing on about 130 net wells. We plan to hold oil and condensate production at roughly 120,000 barrels 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 and 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, and 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 1/3 of our activity on the newly acquired NuVista acreage, 1/3 on the legacy Paramount lands and 1/3 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 barrels per day of oil and condensate. We are maintaining a repeatable type curve, and 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 to 87,000 barrels per day and 1.75 to 1.85 Bcf per day of natural gas. While 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 in 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, but 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.

Please follow the operator's instructions. First question comes from Arun Jayaram at JPMorgan.

I was wondering if you could maybe elaborate on the change to your shareholder returns program in '26, where you're increasing the mix to 75% from 50%. And thoughts, Brendan, how we should think about the mix of shareholder returns post-2026 relative to the 50% to 100% long-term range?

Yes. Thanks, Arun. Yes. So 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. And so that's really the reason for shifting to the upper end of the range this year. And then longer term, we've set a wider range. And really, the thinking here is we want this framework to be durable through the commodity price cycle. 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% to 100% range. And what that allows us to do is be banking that windfall permanently into the capital structure. Then on the flip side, in periods of lower commodity prices below the mid-cycle level, that could push us to the higher end of the range where we're likely to see more value in the equity. So that's the only thinking behind the longer-term 50% to 100% range, and we'll have the ability to flex around that. But 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 very interested in the surfactants program, and perhaps we're surprised that you guys have been doing it for so long. So I was wondering if you could maybe unpack some of the details on the program. What looks to be driving some of the productivity gains versus control wells? And it looks like you're using surfactants more on the completion end or the front end of the well life cycle. Maybe talk about the cost benefit and wondering if you have tested surfactants in terms of moderating your base declines as a couple of your peers have highlighted thus far.

Yes. I love the question, Arun. Yes, there's a lot going on in the company today. So glad you dug in on that surfactant piece. I'll maybe just set up a couple of comments here and then take it over to Greg on the details, but this is just another example of the stacked innovation that we've been talking about. 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. 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 got out ahead of others in this space, and that's what you're seeing us show off today with 300 results already. That's really helped push us to the top of the leaderboard on Permian productivity. So that's kind of a bit of the background, but I'll kick it to Greg here to talk about some of the specifics.

Thank you, Brendan, and thank you, Arun, for your question. You're correct that we are focusing our surfactant program on the initial completions. This is an area we've been developing for several years, and our team has made significant breakthroughs that bolster our confidence in this field. To give you some details, the surfactants we are using are liquid additives incorporated into our frac fluid. They are designed to enhance oil recovery in the reservoir. When these surfactants are pumped downhole, they alter the surface tension of the fluids, which facilitates the release of more oil from the rock, allowing it to flow into the fracture and out of the wellbore, thereby increasing recovery in both the short and longer term, as we have shown over the past several years. Our work in this area has included extensive lab tests and field trials to identify which surfactants perform best in specific zones. We've been optimizing both the concentrations we pump to enhance effectiveness and control costs. As noted in our prepared remarks, we have utilized surfactants in approximately 300 wells, achieving a 9% uplift, which has evolved over time. Initially, we conducted field trials to build our confidence, and more recently, last year we applied surfactants in around 75% of the completions we executed in the Midland Basin, yielding very favorable results. We expect to use a smaller quantity this year in 2026. The outcomes from our completions have been promising. We've also experimented with some producing wells, but the effectiveness there has not been as pronounced, making it a minor aspect of our program. However, our team is dedicated to continued experimentation and will pursue this going forward. We believe this approach is a very effective means to enhance recovery in both the near and long term, and we see it as a significant contributor to our outperformance in the Permian.

The next question comes from Lloyd Byrne with Jefferies.

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 a 9% improvement. Are the costs going up as well?

Lloyd, yes, so this is an interesting question. When we first started this work several years ago, there was some really expensive chemistry out there that was a real barrier to pumping it more broadly just because of the risk/reward feature. Our lab work has really let us trial hundreds of different chemistries here, allowing us to create substitutes that have now kind of almost completely displaced some of those original chemistries that were in the market several years ago. So Greg commented on one of the features we've been fine-tuning is the amount of surfactant that we've been pumping as well as substituting cheaper alternatives. So we've been a little reluctant to be specific about some of this here because we're trying to protect what we think is a competitive advantage. But it's in the hundreds of thousands of dollars a well, is probably a good way to think about it.

Okay. And then just as a follow-up, you've kind of moved from 4 basins to 2 basins and just what kind of opportunity does that give you to cut costs maybe from an organizational structure as well?

Yes. I really appreciate that, Lloyd. With this latest transaction, what we pointed to is $100 million of synergies, but we also pointed to several synergies that we didn't quantify at this time. We think those are going to show up on the infrastructure side. We saw that with the Paramount integration. Now we're kind of stitching together our legacy infrastructure, the Paramount infrastructure and then now the NuVista infrastructure, all 3 of those overlap. There are going to be some of those synergies realized, and we look forward to updating the market on those as we get deeper into the year. There are some organizational synergies here too. Everyone on our team has done just a tremendous job working safely through a lot of change at our company and created a lot of shareholder value. 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 once we get there.

The next question comes from Neal Dingmann with William Blair.

Nice quarter. Brendan, my question is just on the Montney. I'm just wondering, looking at the activity, it looks like maybe about 1/3 of activity coming from the NuVista, 1/3, Paramount and the 1/3, the prior position. I am just wondering if do you anticipate similar activity across the board like that and are those well results pretty similar across the board?

Yes, Neal, you got it. That's about the activity cadence going forward is going to be that 1/3, 1/3, 1/3. Just a quick comment on the driver for that. That's really an outcome of our reoccupation strategy, both in the Permian and the Montney to maximize value from our acreage as we manage the interactions between cubes. A lot has been made over the last several years about the inter-well effect of co-development or cube development, but there is also inter-cube effect as we drill a new cube beside an existing cube. That is a governing feature of our development programs. That, in 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 makes sense. And maybe just a second one 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, is well spacing staying relatively the same there? Or is there any changes?

Yes. Thanks for the question, Neal. In the Permian, we continue to optimize and make small tweaks over time to our well spacing to account for the existing cubes or parent wells in an area, but 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 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. So we're not saving any 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. So no major changes there.

The next question comes from Neil Mehta with Goldman Sachs.

Yes. Brendan, congratulations on the transformation over the last 5 years. My key question is whether you have optimized the portfolio. When you took over, you were involved in 6 areas, and now you're focused on 2. Are you in a good position now? Does this indicate a pause in mergers and acquisitions as you adjust to these changes, and will the extra funds go towards buybacks, or is there another aspect of the strategy you are still considering?

Yes. Thanks, Neil. Yes, the portfolio transition here is complete. We've clearly planted our flag in the Montney and 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 have built.

Okay. I appreciate that. And then just a follow-up is just on the shape of both production and CapEx through the year. I guess, Q1 is a little bit heavier, but I'm guessing that's part of the pro forma portfolio. In Q2, you've got a little bit more maintenance in Montney. Can you just talk about how you're thinking about the cadence for production, quarterly cadence of production, and then capital through the year?

Yes. Great. You nailed it exactly, Neil. The little bit higher capital in Q1 is absolutely just the Anadarko effect. Once we close that, that will come out and we'll just run rate out. I think we've probably said transformation, the highest word count of this call so far. One of the other pieces that we've transformed is the low-level nature of our programs, and that has been over multiple years here to shift to a fully low-level program. We've got that as a really key feature in 2026. We really like how we've leveled out that and it just creates a more predictable and stable business to operate within.

Greg Pardy with RBC Capital Markets.

I had really a 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.

Yes. I love the question, Greg. Yes. So we're really excited about the in-basin sand results that we're already delivering in the Permian, and we're 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 2. This is another great example of stacked innovation, creating value for us. It's also a great example of knowledge transfer and value between the two pieces of our portfolio because this is something that we led the charge on in the Permian and now are leading the charge on in Canada and in the Montney. So maybe, Greg, if you want to give a few comments around the percentage of utilization and where we're headed there.

Yes. Thanks, Brendan. Yes, Greg. So on the Permian side, we've been at local wet sand for a number of years, and essentially 100% of our program is going to 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 fairly mature program. The new news over the last year or so is moving some of that technology north of the border. Historically, most operators will be taking Northern White Sand by rail from the U.S. up to Canada, and that just adds a lot of cost. We're working with providers there to use more local domestic sand. The sources aren't quite as close to the field, but there are good sand sources. This year, we're going to have roughly 50% of our sand pumped sourced in Canada to eliminate that rail charge, and you are 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 hole just the same. That is an evolving technology that we think we're going to 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. And then I'll maybe just kind of staying with Montney now. When you compare and contrast NuVista versus the Paramount acquisitions, can you how do you look at perhaps the degree of low-hanging fruit cost synergies, efficiencies and things like that. I think, Brendan, in the past, you've mentioned NuVista was actually a pretty good operator. I'm just curious on the two.

Yes. I'll begin with geography and then Greg will provide some insights on the integration. The NuVista acquisition really completes the picture for us. With Paramount, we expanded further south than our previous operations, not by a large margin, but we approached the integration with the right mindset to avoid any unintended changes that might create risks. We followed a careful integration process over the past year. One of the key highlights that we shared today is the impressive results from our first density pad, and we are excited about those. In contrast, NuVista is effectively completing the picture, and we are integrating that asset quickly with greater technical confidence. Greg, would you like to share some specifics about how things are progressing?

Yes, for sure. 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 implement the same playbook we used on all the LAP transactions. We came in on day one, took over the asset with a short safety orientation, and then got to work. By that afternoon, we were operating the asset as Ovintiv. There have only been a few short weeks, but we've already connected all the producing wells to our operations control center to 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 will allow us to deliver our synergies quickly. We've already incorporated the $1 million per well of savings from the synergy savings, which you're seeing as part of the guidance. We're going to be delivering that from day one. So far, we've had really, really good results. The teams are integrating well. The new wells remain drilled as expected. Production is already at 85,000 barrels a day, which is what we expected for the assets as they come together. Integration is going quite well. We're really pleased, and I think it will be very similar to the last time but will 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 our transition of the Paramount assets. That result moves 130 wells out of upside into the premium bucket for us. So a really critical result.

The next question comes from Josh Silverstein at UBS.

From a balance sheet perspective, pro forma, 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 levels of debt for you guys going forward? Should we think about it as an absolute level or a net debt level to think about free cash flow allocation?

Yes, Josh. So, yes. So we've reached that target. In fact, we're going to move past it here with the Anadarko proceeds. We're not setting a new target here. If you remember, the $4 billion net target we set was really a trigger for increased shareholder returns, and we spent a lot of time and effort getting to this spot. That is now happening. That trigger is pulled and the catalyst to change those returns is going to be up and running right after we get off this call, I guess. We had to balance that debt reduction as part of our capital allocation for a long time. We've now put ourselves into a resilient position. At the same time, we put the inventory into a strong and resilient position as well. It just means we're in a place where we can focus on keeping the debt around this level and focus on allocating more to cash returns. So that's how we're thinking about the debt level going forward.

Got it. And then from a Montney 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 improve the overall productivity here and then 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?

Yes, I'll turn it over to Greg here, but we are excited about taking these sort of three disparate systems that were previously all operated independently and being able to have one value-creating mindset over all three of them. But Greg, you can comment.

Yes, thanks for the question. In the short term, we're focused on getting the well cost savings at the well level, putting in our completion designs, our facilities designs. That's going to take place immediately over the coming months. Longer term, though, we're really excited about the opportunity to optimize infrastructure. When you look at the map, it just reeks of opportunity. The gas plants are very close to each other, and there are multiple midstream lines crossing the asset. There's a little more in-depth work involved with those midstreamers to maximize the efficiencies in operations. But over time, we will target to drive our T&P down to obtain the gas molecules for the most efficient plant. That's something we'll start working on right away.

The next question comes from Doug Leggate with Wolfe Research.

Brendan, I wonder if I could ask you about asset duration and how you define that. The portfolio repositioning is extraordinary as everybody has observed. But I'm trying to understand, when I asked this question to Diamondback 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?

Yes. Our focus has been straightforward, concentrating on what is necessary to maintain production levels. We are committed to sustaining the returns we are currently generating while managing production maintenance. The reoccupation strategy, along with our approach to cube development and program design, significantly reduces risks to our inventory over time. By designing our annual programs with this reoccupation strategy, we return to drill the previous cubes about 18 to 24 months after the initial drilling, allowing us to effectively sample our remaining inventory through a comprehensive year-long development program in either the Permian or the Montney. This approach gives us a clear understanding of our remaining inventory's duration and performance since we are actively drilling it now. We are not holding back on the less favorable locations for years down the line; instead, we drill the full cubes and reoccupy them as needed. I believe this significantly reduces our risk. If we shared this strategy with you and the results were average, there could be grounds for concern. However, we continue to produce excellent results while implementing this strategy, which truly sets us apart.

I appreciate that answer. I know it's a bit nuanced more than anything else. But forgive me for my second one, but you're probably not going to talk about capital structure and all that stuff. I want to ask you about your philosophical view as the CEO about your commitment to cash returns. If I play back to you what you just said today, you don’t want to be guilty of pro-cyclical buybacks. But that's exactly what you're doing in 2026, if I may say so, meaning that your stock is up 25%. ExxonMobil's is up 22%. Oil is about 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 trying to stay humble here, but a 30% increase still doesn’t reflect what we consider a reasonable valuation for the stock. While we acknowledge the positive momentum, we believe there is still significant intrinsic value in the equity at this time. When we discuss avoiding pro-cyclical behaviors, much of that is connected to the commodity environment. Currently, we are not in a commodity situation that suggests extremely high windfall profits; instead, we remain in a relatively moderate commodity phase. Given this intrinsic value gap, we do not perceive the risk of being at 75% as higher than the current risk due to that value we still see in the equity.

The next question comes from Kalei Akamine with Bank of America.

My question is on the 15, 16 pads. So maybe this is for Greg. Greg, wondering if you can talk about how you sequence the completions of the three zones and share the details on the frac job. That third zone has been an opportunity in the area. 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 derisked inventory count this year?

Yes, I will turn it to Greg. Thanks, Kalei.

I appreciate the question, Kalei. We're really, really pleased with the results there on this 15 to 16 pad down in Karr. What the team has done there, just as a reminder, when we acquired the asset, our base case was 12 wells a section. We said we had upside up to 16 wells. This is the first pad that we really got to design and implement in the area. We kind of met in the middle with 14 wells per section spacing. We added that third zone down in the Lower Montney or some call it, increasing density in the upper part of the cube, pumped a fairly normal frac design for us. We've really leaned in on stacking and spacing. So far, we're really pleased. The pad has been online for a little over 100 days. The lower zones are actually exceeding expectations. The upper zones are holding up very nicely despite the increased density. Our plans now are to move to other parts of Karr and employ this density design. We're talking about 130 of the roughly 600 upside locations between the two deals. This proves up 130 of those. The next step will be to go to other parts of Karr in testing the third zone. We've still got work to do up in Wapiti and in 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 with this design on our future pads and then maybe even lean in a little more when we still have a little more upside potentially, up to 16 wells per section on a few of the pads. We're really pleased but wanted to wait until we had a few months under our belt before we talked about this one. Right now, we're feeling really good about it.

Maybe staying with the Montney here. The second question is on the plant turnaround 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 plant up in Canada. They're on schedules that every 2 to 3 years, you take down the plant for a few weeks to do inspections, routine maintenance, and maybe to upgrade a few of the vessels. These are things that usually we know about well in advance. That's why we're talking to you now about something that's going to happen next quarter. What we're experiencing in this coming quarter is we just happen to have five of them lining up at the same time. Normally, we don't have to discuss much about these because you may have 1 or 2 turnarounds at a time and can move volumes around. However, when you have 5 lining up at once, just requires a little more coordination. We're working with the midstreamers to try to minimize the amount of time that they're down, trying to move volumes around them where we can. There will likely be some impact. That's why we're guiding to be at the lower end of our full year guidance range of 83,000 to 87,000 barrels per day in the Montney. This is something that is infrequent that all line up in the same quarter. Usually, they are more manageable over time.

And 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?

That's going to vary by facility and exactly what kind of work is being done. Usually, these are not upgrades that add capacity. These are more routine maintenance, think of changing the oil in your car; it probably won't run a whole lot better after you're done. In some cases, we could see some minor improvement or flushed production. For the most part, this is just routine maintenance work.

The next question comes from Betty Jiang at Barclays.

Congrats again on the portfolio transformation. Maybe into the buyback. My first question on the Permian. If you mind me digging into the numbers a bit, your lateral length is higher year-on-year. On a total net footage basis, it's almost up high single digits year-on-year, but holding production flat, even though type curve is unchanged. What we would typically expect some upside to that production. Could you just unpack the dynamic there? If we hold up Permian production flat, where could the CapEx trend on a normalized basis going forward?

This is great, Betty. I'll turn it to Greg. The headline here is we are gaining efficiency on the well cost side. We're down 5% on the well costs year-over-year while holding the type curves flat. Over time, this will translate into the total program, but there are some timing effects for 2025-2026 that are masking that a bit here. Greg can cover it.

Thanks for the question. We've been aiming to run our programs on a very level-loaded basis, which has been our goal to complete our wells as soon as they are drilled. We don't carry excessive DUCs. Last year, we had several extra DUCs coming into the year. So in the first quarter of '25, we employed a spot frac crew in the Permian to finish out those DUCs. This had a couple of impacts. One, capital was actually artificially low last year because for all those DUCs, the drilling capital was in the previous year, and we only saw the completion capital last year. The other result was we saw a really nice production boost in the first quarter. We brought on over 50 wells in the first quarter, about double our run rate for the other quarters in the year. Such a positive for last year. Unfortunately, for the metrics, we don't have that same circumstance this year. We're holding true to very level-loaded program that allows us to be more efficient, executing repeatedly completion-wise on capital and production every quarter. The building blocks of the guide are a slightly lower cost per foot, same type curve. The only difference is the timing. This program is a very efficient model in which we've executed effectively and will continue to prove over time.

My follow-up on the Montney surfactant use. It seems there is a lot of operational efficiency tailwind in Montney, but specifically, are you testing the surfactants in Montney as well? Is there any crossover viability there?

Yes. I think I'll say Greg here, but we found that every bench in each county will perform a little bit differently depending on the wettability and fluids. The Montney has a wholly different down subsurface regime from temperature and pressure perspective, so it's going to have its own bespoke completion optimization. Some of that might be surfactant and some is looking like other pieces that can be added to performance. It will be a bit different. We're quite advanced on surfactants in the Permian with 300 wells pumped there, but we're excited about completion design in the Montney generally. We'll see surfactants go a little slower there given the downhole temperature and pressure differences, but Greg, over to you.

Yes, we're in our seventh year of surfactants in the Permian, and we've learned so much during that time. We've learned where they work best, what concentrations to use, which surfactants are most effective for the lowest cost. We're still in the early innings in the Montney. The team does an excellent job sharing learnings cross-border and cross-assets, so we're looking at things up there and have done some rock work and a few trials so far. I would position it as we're just getting started, but the whole toolbox is available to us. We'll apply the same high completion intensity, stacking, and spacing optimizations that we apply in the Permian, but it will be a different setup in the Montney.

The next question comes from Phillip Jungwirth at BMO Capital Markets.

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? Where that might be across North, South and any plans to test this?

Yes. I'll turn this to Greg. But we're really pleased with the job the team has done here to assemble a position in the Barnett. But Greg, over to you.

Yes. We've been very interested in the Barnett and have been watching it for some time. This is one of those plays we’re, wise to learn from our peers. The Barnett is a deeper zone, it's got more pressure and looks like it’s showing good productivity, but the higher costs are something we're watching as some of our peers are derisking their cost side as well as the well performance. We do have a meaningful Barnett position; we’ve got Barnett rights on about half our acreage position in the Permian, around 100,000 acres. We plan to test that this year with our first well to gather some information, but we are also being prudent regarding how much we lean into Barnett and considering how it plays alongside our current cubes; it won't be impacted by the shallow production. We have time to be patient but also the ability to fast follow and execute on that 100,000 acres if we choose.

Can you talk about what you've seen with LNG Canada ramping up the second train starting up, as it relates to the AECO market and Ovintiv supplying that versus maybe incremental equity volumes for the partners? Hypothetically, would changes in ownership across the facility have any implications for Ovintiv or open up any strategic partnership or marketing opportunities?

Yes. We are pleased to see that facility ramp up to essentially full capacity, which is the first time since the startup that it's been at that level. It's been a slow grind upwards with ups and downs. Our caution on AECO remains the key takeaway from LNG Canada. While it's great to see it at that level, it’s still relatively small compared to the total productivity potential of the basin, and we've seen the behind pipe volumes able to fulfill that takeaway. We continue to be interested in diversifying our Canadian gas portfolio into alternate markets, which is part B of your question there. Over time, we will probably grow that exposure.

The next question comes from Kevin MacCurdy with Pickering Energy Partners.

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. 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? What could change that rank?

Yes. Appreciate it, Kevin. The two things we've discussed respecting growth are still in place. We do not see a fundamental call for incremental barrels or BTUs today. The market's not begging for companies like ours to bring more volumes into the market. That's gate one. Gate two is can we create more cash flow per share growth from share buybacks or incremental rigs? Today, we see that equation tilted towards the buyback. We expect we get a better cash flow per share outcome from buying the shares. The combination of both of these gates today are telling us to stay in maintenance mode. I appreciate your question because it surfaces another aspect of the portfolio transformation that's important; we've added tremendous inventory duration and focused the portfolio but we've also unlocked growth potential. At some point in the future, that will call for growth, and we've now created the capability to do that efficiently.

The next question comes from Dennis Fong with CIBC World Markets.

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 talk towards how that helps you gain comfort with existing depth as well as how that may influence allocating capital, both North and South of the border, which looks kind of balanced from a well count perspective?

You got it, Dennis. That ground game has been really effective for us. A lot of focus on the larger transactions, but the ground game has been grinding away very efficiently. Where we've arrived at here, we've put the transaction risk of needing to build inventory duration behind us. Now we can rely on that ground game, which is a data-efficient low-cost way to sustain our inventory duration. It funds within our current framework and balance sheet. We like this feature, and we're proud of how the team has been able to do that. As far as capital allocation between the assets today, we're holding those assets flat for overall balance.

Shifting on to innovation. There's a lot of questions today focused on using surfactant, obviously your teams have done a wonderful job in leading-edge technology on improving operations. I'm just curious if you guys have learned potentially from the NuVista teams and operations that they were doing or techniques that they were running that could be applicable to your existing Montney base or even the Permian.

Yes. No, we love that question, Dennis. This is one of our mantras; one infinite rate of return we can generate is by learning from someone else's capital. What better way to do that than in an integration where we have full transparency and data. I'll let Greg discuss some things we've been excited about from the NuVista team.

Yes, we were very pleased with the NuVista transaction. Not only did we get great assets, but we also gained a number of talented individuals who came over with the transaction and brought really good ideas. Out in the field, they've done a fantastic job with their gas lift designs and how they’ve optimized those techniques. We're already working with them to apply those ideas more broadly across our portfolio. This will have some application in the Permian, but definitely in the Montney. We've talked about the precise meter where you're going to land the wells, and they have really good ideas that will help us drill wells faster than we have in the past. We’re implementing that into our program.

At this time, we have completed the question-and-answer session, and we'll turn the call back over to Mr. Verhaest.

Thanks, Joanna, and 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 you to please disconnect your lines.