Ovintiv Aktie

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2026 Second Quarter Results Conference Call. As a reminder, today's call is being recorded. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the expressed 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 second quarter '26 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 our disclosure documents filed on EDGAR and SEDAR+. Following prepared remarks, we will be available to take your questions.

I will now turn the call over to our President and CEO, Brendan McCracken.

Thanks, Jason. Good morning, everybody, and thank you for joining us. Our second quarter results demonstrate the strength of our durable return strategy and the business we have built. Our future is also looking bright with a boost to our oil production, driving more free cash flow, differentiated cost and productivity results, the demonstrated ability to replace our inventory and ramping buybacks. We have demonstrated industry-leading operational performance through stacked innovation and execution excellence.

Our culture, our expertise and our unique private data set have created a distinct operating advantage. We have materially fortified our balance sheet, bringing our leverage ratio well below 1x. We continue to demonstrate our proven track record of capital allocation, while delivering superior durable returns to our shareholders. We are one of the most innovative, efficient, opportunity-rich E&Ps in North America and we are very excited to be operating from this position of strength.

Both our Permian and our Montney year-to-date results are tracking above type curve and continue to lead the league in their respective basins. This is driving an increase to our full year oil production guidance, which equates to about 4% growth on a per share basis with no additional capital or activity. Our cash flow per share and free cash flow both beat consensus estimates by a significant margin this quarter, and we returned approximately 63% of free cash flow to our owners through share buybacks and our base dividend.

Our net debt was below $3 billion at the end of the quarter, marking the lowest leverage the company has had in over a decade. Our capital structure has been rightsized, and our leverage now compares favorably to our peers.

Earlier this year, we revised our shareholder return framework to be more flexible and deliver enhanced returns to shareholders. Our year-to-date shareholder returns total about 45%. For the second half of the year, we expect to be more active in our buyback program, targeting full year returns of more than 60%. We continue to see a substantial gap between market value and the intrinsic value of our business at mid-cycle prices. With $1.3 billion of free cash flow year-to-date, a leverage ratio of less than 1x and a strong outlook for the rest of the year, we have the capacity to buy back a substantial number of shares and continue to advance our ground game strategy.

We have assembled one of the most valuable premium inventory positions in our industry. 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. Our work to build inventory depth means that we have nearly 15 years of premium inventory in the Permian and close to 20 years of premium oil inventory in the Montney. This expansion has been unmatched by our peers. In fact, over the same time period, most companies saw their inventory life decline.

Our goal now is to maintain our premium inventory through ground game bolt-ons and organic additions. Already this year, we have essentially replaced the 2026 drilling program in both assets. With Barnett locations, we've identified on our existing acreage in the Permian and the successful density tests we have executed in the Montney, which converted upside locations into the premium category.

We have worked for years to design and optimize our approach in order to maximize the returns and value we generate from every acre of resource we develop. We have deliberately built a culture of relentless curiosity that seeks to create our own innovations, but equally also seeks to learn rapidly from the innovations of our peers. We inform our design and optimization decisions from our expansive private data set, and we've built institutional capability to execute on the leading edge.

Our culture, our expertise in our private data combined together are hard to duplicate. That has led us to our stacked innovation model, where we stack multiple innovations together to create industry-leading results, which defy the broader U.S. shale trend of performance degradation. We've deliberately taken a different approach than many of our peers. The result is that we have -- we are consistently one of the highest oil productivity, lowest cost operators in both the Permian and the Montney. We have over a decade of experience deploying our systematic cube development approach, which means we codevelop multiple stacked zones from a single pad. This creates value by maximizing both returns and resource recovery.

We also have around 5 years of experience deploying our reoccupation strategy. We have found that the optimal timing to drill an adjacent cube is roughly 18 to 24 months after drilling the first. This minimizes pressure depletion from the first cube into the next and is a dominant driver of our development schedule. As a result of our cube development in combination with our reoccupation timing, each annual program samples wells from across our rate of return creaming curve, not just the highest return wells. This means greater predictability in our annual program results. We can deliver consistent and repeatable results year after year because we have not burned through our highest return inventory, and we have maximized the value of every acre. This means we expect to continue to generate the superior returns we're generating today for many years to come.

If our approach was to offer consistent the mediocre results, I think this would be a debate about whether that was the right call. However, generating the highest oil productivity at one of the lowest costs consistently is a slam dunk combination.

The completion space has been the source of several cost and productivity-enhancing innovations such as Simulfrac and Trimulfrac, advancements in stage architecture design, wet sand, proppant intensity and surfactant usage. The implementation of any one of these items often builds on or depends upon the previous implementation of another. Today, our Frontier innovations are powered by AI to leverage our extensive private well data set, optimize our technical workflows and operational execution in real time. We are using this new technology across our portfolio. This has led to faster cycle times, enhance production, reduced downtime and significant cost savings.

The ability to successfully integrate new technology and innovative techniques across the portfolio is anchored by our deep institutional experience and expertise. It's what enables us to identify, test and scale innovation rapidly across our portfolio while maintaining cost and productivity leadership.

I'll now turn the call over to Corey who will speak more to our second quarter results and our guidance updates.

Thanks, Brendan. Our second quarter results continued to build on our track record of consistent execution. We delivered cash flow per share of $4.46 and free cash flow of $682 million, both beating consensus estimates. Our oil and condensate volumes averaged 206,000 barrels per day, above the high end of our guide, with total volumes coming in at 615,000 BOEs per day. The oil and condensate beat was driven by the Permian, where we continue to see strong new well results as well as outperformance from our base production.

We successfully navigated some extended downtime in the Montney due to a series of planned plant turnarounds. The impact on our condensate volumes was minimal as we were able to prioritize flowing our most liquids-rich wells, but this meant we came in below the low end of our guidance for natural gas volumes. The revenue impact of the lower gas volumes was negligible as AECO prices were quite weak during the quarter. The turnarounds were all completed during Q2, and we expect our Montney production volumes to be more stable through the second half of the year.

We also reduced net debt by about $3.4 billion, using the proceeds from our Anadarko disposition as well as a portion of free cash flow. The resulting quarter end net debt balance was $2.995 billion, bringing our leverage ratio to 0.6x. This is a major milestone for us as debt reduction has been a key focus for several years. The stronger capital structure also resulted in Fitch upgrading our credit rating to BBB from BBB-.

Our team is continually focused on improving our capital efficiency and our outstanding operational performance through the first half of the year gives us confidence in what we can achieve through the second half. We've seen consistent outperformance from our Permian asset relative to the 120,000 barrels per day run rate we set for the asset several quarters ago. This has been due to a combination of strong productivity from our new wells along with our outperformance from our base. We are raising the Permian's go-forward run rate to 125,000 barrels per day and our full year total company oil and condensate production guidance to 210,000 to 212,000 barrels per day. When combined with year-to-date share buybacks, this equates to oil growth of about 4% on a per share basis with no additional capital.

While Montney year-to-date well performance has exceeded our 2026 type curve, higher royalty rates from higher condensate prices are expected to keep Montney volumes between 80,000 and 85,000 barrels per day. Our full year NGL guidance is also increasing to about 84,000 barrels per day, and we are maintaining the midpoint of our previous natural gas guidance at 2.05 Bcf per day. Our portfolio has deep inventory duration and the capability to further grow top line production in both assets. However, we believe it is still prudent to maintain efficient, level-loaded programs in both the Permian and the Montney and that higher oil prices accrete to free cash flow versus investing in drilling more wells.

We're not currently seeing significant inflationary pressure on our 2026 capital program outside of higher diesel costs. We expect to offset any additional cost inflation with operational efficiencies. As such, our full year capital guidance remains unchanged. In the third quarter, we expect production to average approximately 628,000 BOEs per day including about 208,000 barrels per day of oil at condensate and our capital spend is expected to come in at around $575 million, consistent with the second quarter. Activity in both assets is expected to be fairly ratable for the rest of the year.

I'll now turn the call over to Greg, who will speak to our operational highlights.

Thanks, Corey. Across our acreage footprint, our Permian well productivity continues to be strong. Year-to-date performance has exceeded our type curve, which is unchanged from last year. With average second quarter oil and condensate volumes of 127,000 barrels per day, extending the outperformance we saw in Q1, we're increasing our expected run rate in the play to 125,000 barrels per day.

We realized strong Midland oil prices this quarter, which traded at 7% premium to WTI. Our U.S. oil volumes also benefited from the WTI role, which added about $5 to our oil price realizations. Our Permian gas also benefited from relatively strong Houston Ship Channel pricing this quarter with less than half of our volume selling into Waha, we avoided the deeply negative price realizations experienced by some of our peers.

Our Permian productivity uplift is coming from both our new wells and our base production. This is thanks in part to our cube development approach and reoccupation timing as well as the benefits of stacked innovation. Using public data from Enverus, you can see that our Midland Basin wells continue to significantly outperform the peer average. They have gotten better every year since 2023, and our 2026 year-to-date results really stand out.

There are several factors at play here, including surfactant use in our completions design. We've now completed about 400 Permian wells with surfactants since 2019, and we see about a 9% improvement in oil productivity versus a non-surfactant treated well. We think surfactants account for roughly half of the productivity uplift we've seen over the last few years. At a cost of only $100,000 per well, these custom treatments are generating impressive returns.

Our base production is also outperforming year-to-date, and we now expect to see a 3% improvement from our original plan. A good portion of this is due to the remote operating capability of our Permian operations control center, where the team is using AI and automation to optimize artificial loop parameters, reduce downtime and flatten well declines. This is technology that we imported to the Montney, and we are now seeing the benefits across the portfolio. Our team leaves no stone unturned in pursuit of making better wells for lower costs.

Moving north now. Despite some noise during the quarter from plant turnarounds and higher royalty rates, our Montney well productivity continued to be very strong, tracking above our 2026 type curve. The plant turnarounds are now behind us, and I'm very proud of the way the team was able to limit the impact on our most liquids-rich wells, especially given the strength of condensate prices during the quarter. And while higher condensate prices did result in higher royalty rates, the revenue uplift far outweighed the impact of lost volumes.

Our realized price for the Canadian condensate was about $94, which was a premium to WTI. Although we don't like losing the reported volumes, we remain focused on the bottom line. Based on current strip pricing for the second half of the year, we expect our Montney condensate volumes to average 80,000 to 85,000 barrels per day.

Also of note was our Montney gas price realization at 187% of AECO. Our diversified portfolio of both physical sales out of the basin and financial arrangements to price our gas away from AECO continues to be highly valuable. Uniquely this quarter, our realized gas price was boosted by sulfur revenue. Sulfur is a byproduct of our gas production in certain areas across our Montney acreage. Typically, it is an expense to extract this product from our gas stream and transport it to the West Coast market.

In the second quarter, however, sulfur prices were historically high and contributed about $40 million in revenue. While it's hard to predict where prices will go over the longer term, we do expect sulfur prices to remain strong for the rest of the year.

Our Montney team continues to push the boundaries on cycle time improvements. Year-to-date, our completion speed averaged more than 4,900 feet per day or about 20% faster than our 2023, performance and about 40% faster than the current pace of our Montney peers. We recently established a pacesetter of more than 7,000 feet of completed lateral length per day using Simul-frac , and we are very excited to test the repeatability of this result over time.

We also achieved an industry milestone with the first ever 100% domestic wet sand pad in Canada. This is another example of stacked innovation that we've successfully transferred between assets. Compared to importing dry sand to the Montney, domestic wet sand is roughly 20% cheaper. The combination of faster cycle times and consistently strong well performance with innovations like wet sand, results in industry-leading capital efficiency and highly competitive returns.

We have long been believers in the benefits of diversification when it comes to managing natural gas price exposure. We utilize a variety of structures, both physical and financial to price our gas away from the oversupply to AECO and Waha hubs.

We have the least AECO exposure of our Montney peers, the most diversified portfolio of market access and consistently realize a material premium to in-basin pricing. We also have one of the highest gas price realizations among our Permian peers. We priced more than half of our gas outside of Waha with exposure to GCX, Whistler, Matterhorn and starting later this year, the Hugh Brinson pipeline. The result is that despite producing gas in 2 of the weakest price basins in North America, our gas is generating significant revenue. During the quarter, our total company gas price realizations, including hedging, was $1.99 per Mcf or about 70% of NYMEX. We will continue to pursue opportunities to further diversify our gas price exposure over time.

I'll now turn the call back to Brendan.

Thanks, Greg. Halfway through the year, we've generated more than $1.3 billion of free cash flow, organically replaced our full year 2026 drilling locations in both the Permian and the Montney, brought our debt down below $3 billion, and are set to grow oil production per share by 4% with no increased activity or capital spending. Our execution continues to lead the industry, underpinned by culture, expertise and data. Our portfolio is best-in-class. Our balance sheet is rock solid, and our stacked innovation and disciplined approach to capital allocation are driving compelling returns.

This concludes our prepared remarks. Joanna, we're now ready to open the line for questions.

[Operator Instructions]

Neil Mehta with Goldman Sachs.

Thanks for the update. And obviously, really impressive results. I just want to focus on Slide 12 here and give you an opportunity to unpack some of these stacked innovations that are driving this productivity improvement. And in particular, the surfactant seem to really be driving a lot of this upside. So can you just talk about some of the technologies that are at work here? Which ones are you most excited about? And what's the sustainability of the advantage because the old adage, there are no secrets in the Permian is something that there's some truth?

Yes, Neil, yes, thanks for the question. I appreciate the interest here. First thing I would say is the surfactants have obviously been a big piece. We've been pegging it at about a 9% uplift on our type curve. So obviously really important, but far from the whole story. And that's why we've taken the time to walk through the whole stack of innovation all the way from our cube development approach through to things like the stage architecture where we very carefully engineer these fracs with about 70 different input criteria that we select to deliver the maximum recovery all the way through to surfactants, like you said.

So it is a real system. What we find is each of these factors are interrelated and affect the other. So the holistic design matters, and it has taken us years of work and data accumulation both through our own development, but of course, through our active data trading strategy as well to accumulate the ability to define causality. And defining those causal relationships is what's really valuable in the subsurface, particularly on productivity and recovery.

So that's the fundamental basis. If you think about your point on there's no trade secrets or intellectual property in the Permian, I think that's true of the industry overall because we get on calls like this and talk about all the recipe. And so really where the moat comes from, the competitive moat that we've been able to build is the whole system here. And that's why we've taken some pains to describe it as it starts with the culture that relentless curiosity, not just to come up with innovations ourselves but to observe them in what's happening around us.

We have this saying in the company that only infinite rate of return is learning from somebody else's capital. And so we really have built that into our culture. It obviously comes from the expertise side where we've created this institutional capability to be able to execute at this leading edge. And that's really valuable. Like you can't replace the years of experience that allow us to perform the logistics, the supply chain and the engineering and geoscience to know what the right thing to do is, that's all institutional knowledge that -- while the headlines are available and knowable, the details of how to go do that as a company at scale are actually really hard to mimic and duplicate.

And then the final thing is the private data where we've assembled a very large, we believe, unique private data set across both the Montney and the Permian that allow us to establish those causal relationships with confidence and then be able to incorporate them into our designs at scale. So yes, that's, I think, the answer to your question.

That's really impressive. And then Brendan, I don't know if you can comment on this, but a lot of focus on TSX inclusion as they have changed some of the -- potentially the foreign domicile eligibility criteria. Can you just take us into any conversations that you're having? Or how you're thinking about that potential as that could change the shareholder base and be a catalyst for the story?

Yes. It's a great point. There's some news just this week actually on that front. So S&P has begun a formal comment period that they kicked off earlier this week, that comment period is open until August 21, on the potential inclusion changes for the TSX indexes. They've also indicated that following that comment period, they would look to make any changes to the inclusion ahead of their September rebalancing, which would be a September 18, event.

So -- and in that comment process, they have specifically called out Ovintiv as 1 of 3 companies that would meet the proposed criteria for eligibility to be included into the TSX. So that is all news and constructive. We'll obviously have to wait and see for that comment period to conclude and see what their final decisions are. But if you take their proposed methodology, which would have a 50% weighting for companies like Ovintiv that would imply we've seen some analysis even just in the last 24 hours here from several of the banks that have been following this. We've seen anywhere from 3 million to 7 million shares of direct buying from the index funds. And then, of course, we would expect some active buying there could be multiples of that coming from the active managers that are -- we would now be in their benchmark.

So all of this is constructive for us and I think comes at a great time for us as well because a lot of interest in what we've created here and from the Canadian Investor. And then as well, at least a couple of Montney players that are going away through transactions, one of which was NuVista that we acquired and then ARC is the other one was shelved. So definitely all a tailwind for us.

Greg Pardy with RBC Capital Markets.

I wanted to take one maybe just to build on what Neil was asking about. But how much of the difference is there in terms of the implementation of surfactants in the Permian versus the Montney. And then I'm just curious as to maybe at what stage have you begun to implement in the Montney? Or is it very, very early stages there?

Yes, Greg, I appreciate the question. It's a good one. So we are very early stages in the Montney. So we've been relatively advanced in the Permian. This year, almost every well is going to have a surfactant treatment. And then in the Montney, we're just really getting started there. So the lab results are very encouraging. If you think about 4 or 5 years of cycle time in the Permian, we're going to be able to accelerate that in the Montney. So I don't think it's imminent to have a conclusion on the efficacy in the Montney, but definitely going to be able to accelerate relative to the pathway we took in the Permian, and so we're building on that knowledge and applying it up north, which is really exciting.

Okay. All right. And then I'm just trying to -- I'm trying to reconcile shareholder returns, the balance sheet, dividends. I mean, you're in an awfully good place now, right? The net debt has really been slayed. Curious as to maybe what you kind of think about as being an optimal capital structure. And then I believe you said you're kind of 45% in terms of shareholder returns in the first half, that's going to be 60%. But I mean, if your shares are trading at the discount, they are vis-a-vis intrinsic, and I think we'd agree with that, then do we see a big emphasis on buybacks as we go through the back half of the year? Or do you still think that there's some room, it's probably a better question for Corey, but do you still think there's some room for net debt reduction?

Yes. I think you painted it out there, Greg. I think, obviously, we don't have a crystal ball on exactly where commodity prices are going to go from here. It's been a dynamic last few months and even last couple of weeks here. So we're mindful of that. But at the same time, we see a big intrinsic value gap in the shares. And so we see a lot of value in buying shares back, and that's why you're seeing us lean in from roughly 45% year-to-date to the signaling that's going to be at least 60 or 60 or greater for the rest of the year, so -- or for the full year.

And so -- from a capital structure perspective, we feel really good about the capital structure that we've created in the business today. So -- and like you said, lots of free cash flow to enable the combination of buybacks. And then we have also said the ground game can be funded out of that free cash flow as well. I would comment specifically on that to say you should expect something in the -- these are going to be the modest size deals. We think we've got line of sight in both the Permian and the Montney to do deals like that at very attractive entry points from a dollar per location perspective, which has been our track record here. So you should think about that ground game being in the low hundreds of millions of dollars type of range.

Neal Dingmann with William Blair.

Brendan, my first question is just around what I would call your really appropriate described stacked innovation approach. Specifically, have you all applied this approach now fully or started, I guess, you even started applying this approach to the Montney. And if so, if you haven't yet fully yet, do you plan to -- do you and Greg plan to do that in the coming quarters?

Yes. So we're early days and excited about that. I think we're early days in both places, to be honest. I think the stock just grows with time. But I'll turn it over to Greg to provide some color on that.

Yes. I appreciate the question. I think if you think about all of the stacks that you see there on Slide 8, each one of those is the culmination of years of work in each one of the plays. So things like cube development and spacing and stacking, we've been doing that in both the Permian and the Montney for, gosh, a decade now. But things like Simul-frac, wet sand, that's had different levels of application in each of the 2 plays.

We continue to improve how we do that in the Permian. And I think we're a little earlier in the process on how we're doing that in the Montney. As we just reported our first wet sand -- full wet sand trial in the Montney this quarter went very well. We think we're going to lean into that more as we go throughout this year and into next year. We'll take a little bit of time for the infrastructure to catch up there. But -- so we're different places with each of the technologies. I think the one I'm most excited about is the AI and the new digital tools we've been building on both sides of the border using those to help not only on drilling and completion efficiencies, but also on base production. So I think in different places in each of the assets on the stack, but applying it across the board, and there's still room to go from here.

Makes sense. And then just second -- my second question is really diving in on the Montney GP&T. Specifically, could you talk about potential future GP&T cost savings? I mean it assumes now that given you have such a massive position now after adding the Vista and Paramount. What type of potential is there to reduce GP&T now that you have such a large position up there?

Yes. Great question, Neal. The T&P, if you look at how it's broken out by country, the majority of it is in Canada and our Montney operation. And so what we're excited about here is we're really just getting going with the 3 positions being combined together that is our legacy position, the Paramount position and then the NuVista position. And when -- if you remember, when we did those deals, we signaled, hey, there's a bunch of tangible synergies we're going to go get.

Those are all now incorporated in the business fully realized and this is the longer-term mission is to go find some more profitability by combining those positions together. And one of those big buckets is going to be around the T&P.

So we do expect this to unfold over time. It's probably going to be a multiyear process for us. It's not an overnight thing. And so we don't have specific guidance baked into this year. But the message is we're very focused on this as an opportunity to drive free cash flow growth going forward.

Arun Jayaram with JPMorgan.

Brendan and Corey, you guys have raised your second half Permian crude and condensate guidance to 125,000 barrels a day versus the previous messaging around 120 as being kind of the run rate. I was wondering if should we perceive this as the go-forward cost maintenance kind of or sustaining production rate in the Permian. I was wondering if you could just unpack that a little bit.

Yes. I'm going to let Greg take the win on this one. So it's really his team that delivered that for us, Arun. Yes, go ahead, Greg.

Yes. So thanks for the question, Arun. And yes, first off, we are saying 125 is the run rate go forward in the asset, so not just the rest of this year but beyond. As we think about how we got there, first, I'd just really like to start by acknowledging the great work done by the team, executing on a very efficient level loaded program. And this run rate is assuming a level-loaded program in the Permian. So we're not adding more activity or more capital. And over the last several quarters, we've been talking about some really exceptional results we've seen in the Northern Midland Basin from some of the Dean wells up there. That performance has persisted.

But more importantly, we've seen that really good performance across the portfolio. We're seeing strong results from our new wells and all of the areas that we have in the play. And so that performance has given us a lot of confidence. But the other thing that's probably the most exciting is how that performance has persisted over time and is translating into stronger base performance. So not only good new well performance, but the base is very strong on some of those newer wells, but the team has really put a lot of effort into some of our older wells.

So working on the base through our operations control center there in Midland, we've been able to improve run times from our ESPs. We run a lot of the monitoring and optimization in-house on rod pumps. We built AI tools, put in automation. All those things are helping us minimize failures, optimize production. And when we do have failures, we're able to get our wells back online quicker with some of the automation that the team has put in. And all of that results in fewer, zero days with shallow declines and have really helped the base. So it's going to be a combination of the new well performance, the base performance, all of that coming together gives us confidence, and that's what allowed us to say we're going to be at 125 run rate going forward.

Great. Just a quick follow-up. In terms of the Montney well productivity in '26, I was wondering if you could maybe speak to maybe some of the drivers of that. It sounds like surfactants are maybe not quite the driver, but I'm thinking maybe a little bit of mix between maybe some of the new properties a little bit more activity at Karr, Wapiti. Just maybe give us a sense of what's driving that?

Yes, I'll take that one, Arun. We've actually seen really strong results across the entire position. We've had really strong results in our legacy wells up in Dawson. We've had some good pads in Pipestone as well as areas like Karr and Wapiti that are newer to the portfolio. So we've seen really strong results that are a result of the stack innovations. We've been working on our stage architecture. We've been looking at proppant intensity. All the things that we've done in the Permian, we're doing those same things up in the Montney and just seeing really strong well results across the portfolio.

We've leaned in on density a little bit on some of the newer properties down in Wapiti and Karr,those density tests are also performing as expected in most cases. And then some of the zones are actually doing a little better in the deeper zones down the Sexsmith. So we're very pleased with the results across the portfolio in Canada and expect that to continue.

Doug Leggate with Wolfe Research.

I got 2, Brendan, if you don't mind, one for Greg or perhaps it's for you and one for you or perhaps is for Corey. But -- so my first question is on the Proppant and the wet sand and the clear impact this is having on what appears to be your decline curves. That, over time, would imply that your capital efficiency is improving and your sustaining capital would theoretically decline unless you take the higher production.

So my question is, do you maintain the activity, maintain the spending? Or do you take the efficiency flatline the production and have lower spending? And you know what I'm getting at, either do you beat the numbers or do you cut the capital?

Yes. It's a great question, Doug. And it is one that we think about. And if you look at our history over the last several years, we've done a little bit of both, when commodity prices are elevated like they are today and our ability to grow those volumes and create more free cash flow makes a lot of sense. That's what you've seen and then equally at a couple of instances over the last few years when commodity prices have been lower, we've pocketed the capital savings and created more free cash that way.

So in this instance, we've done the value creation through the production growth. And that's what you've seen us announce here today with the 4% bump on a per share basis. That's a combination of both organic growth, but then also the buybacks on the denominator side.

So, yes, we really make a value-based call depending on the circumstances. And today, it makes sense to hold that activity flat and let the benefit accrue to volume growth and free cash flow that way.

We'll continue to watch. I think, Brendan, you'd be disappointed if I didn't bring up the cash return issue. We all heard Greg's question earlier. And I wonder if I could -- this is my follow-up. Look, we like a lot of people have been very supportive of everything you've done. And we worry that at some point, an investment case becomes more about the oil price than it does about the company. So here's -- that's my kind of precursors, but here's my question.

You're now sitting at a $17 and change billion market cap with $3 billion of net debt. That's $20 billion of enterprise value. That means you're essentially discounting a $2 billion free cash annuity with a two-and-change capital program. That's the $4 billion cash flow number that you gave us last quarter to justify your buyback on the basis of value. So you're basically there. Your net debt [indiscernible] and you're swinging the share price in the last 3 months is $11. Why not take this windfall and hit the net debt because you're -- what you justified as the basis of your valuation unless you've changed your oil price view, you're basically there?

Yes, Doug, you cut out just a little bit there, but I think I got the gist of your question around the decision on how much buyback to do versus how much debt reduction to do. And, look, I think this is another question we ask ourselves all the time and do a lot of thinking about to make sure we're thoughtful about how we allocate capital for best value. And so that's why you see us taking the approach we're announcing today. We think the greater than 60% guidance is prudent. We don't have a crystal ball on exactly how commodity prices unfold here. But clearly, our business is performing well and generating a lot of free cash flow, which allows us to both buy back a meaningful amount of shares and continue to reduce debt.

And so that's the track record. Of course, we're just on the heels. In the quarter that we're releasing today is $3.4 billion of debt reduction. So clearly, we agree with the thesis of running these businesses at low leverage. And I think your note called it a top quartile amongst peers leverage company now. So that's been our ambition. We're pleased to have gotten in here. So I think it's -- I think we're taking a prudent and balanced approach with the capital allocation.

A debt issue. But I appreciate the answer, Brendan.

Yes. The part of that prudence is the value that we see in the shares today.

Gabe Daoud with Truist.

Maybe a question for Greg. I was wondering if we could maybe get your updated thoughts on the Barnett. I know you had that 100,000 acre position held by production. But curious, what are the plans there? I think you're supposed to be drilling a well there this year, I believe. But curious, Greg, if there's maybe any update there?

Yes. I'll pass over to Greg here, Gabe. One thought just quickly to set that up because there's been a couple of questions overnight. The Barnett position, the 100,000 acres of Barnett that we disclosed last quarter is all on existing acreage. So we didn't -- there's been no transaction there. This was in our acreage that we've held into play for a decade plus a year now. And so -- so a real great opportunity for us to work our way into the play in a fashion that learns from others. It's a great example of that stacked innovation approach where sometimes we're the ones leading the charge. And sometimes we can sit back and have the benefit of other people's risk dollars. But Greg can talk about where we're at on our Barnett well.

Yes. Great. Thanks, Brendan. Thanks, Gabe, for the question. As an industry, we're learning a lot about the Barnett right now, as you see, there's a lot of activity going on throughout the basin, drilling wells, bringing them online. So we're seeing a lot of data from our peers that are operating around our position that has given us encouragement, as Brendan mentioned, these are held acres. So we don't have to go out and drill wells today, but we are excited to continue to learn more.

We've already started drilling our first well. We've drilled and cord. The vertical, the core looks very encouraging. This is a well in Martin County that we're doing currently. And now we're proceeding with drilling the lateral. That well will come online late this year, which should give us a lot of information around the productivity should teach us a little bit about well cost and how efficiently we're going to be able to drill these wells. And then that also gives us a lot of trade currency. We can trade that core well data with our peers to learn more about what they're learning here. And we're also participating in really small working interest with some peer wells.

So we do have a growing data set that we're learning from, but we are taking the approach generally that we're going to watch others try to delineate where the different product windows are in the play, and help us learn what costs are ultimately going to be. But I would envision us drilling this 1 well this year, next year, another well or 2, we'll just see how our progress goes there. But we'll be learning all along the way and making sure we optimize our position.

That's great color. Thanks, Brendan, for clarifying that. And then my second question, guys would just be on the heels of the Pembina Meta announcement, I guess, a couple of weeks or maybe a month ago. Just curious maybe anything to highlight on your efforts on the data center front?

Yes, Gabe, thank you. Look, super encouraged. I think the market continues to develop. And what we're ambition, our strategy is to continue to diversify our gas sales away from AECO. And so this is another outlet that we're excited about, which is the emerging data center build-out in Western Canada. We do expect that this will be a place we can put some of our gas over time along with the growing LNG build-out that's happening off the West Coast.

So all of this is constructive for our ability to diversify our gas away from AECO. So more of the same there. And I think Greg and Corey did a good job of highlighting the benefit we're already seeing from that strategy in our gas realized prices.

Scott Gruber with Citigroup.

I want to come back to the balancing of the cash return question and the question about putting more cash on the balance sheet. Has some peers have delevered, they've started discussing a willingness to use their balance sheet during industry sell-offs to juice buybacks in order to try to reduce the equity volatility. Brendan, is that something that you would contemplate over time with the balance sheet as healthy as it is? And -- and would you think about positioning for the balance sheet for that over time?

Yes, I think it's a good question, Scott. I think it's certainly something we'll be thoughtful about. We're new to this space. We're excited to be here, but sort of having just arrived here, those are the types of questions that we're asking ourselves. And I would not take that off the table, and it's obviously down the road relative to where commodity prices are today, but we all know that, that eventuality could occur. So I think that's something we've put on the table and decision as we go, but our overall orientation will be all about value, where do we see the best value for our capital allocation.

That makes sense. And then on CapEx, you highlighted your diesel displacement strategy, which is important today given where diesel prices are at. And I know you guys utilize eFrac in the Permian. But curious, what other steps are you taking to try to reduce your diesel consumption across your D&C spend?

Yes, I'll let Greg take that one on.

Yes. So great question. In addition to using electric frac fleets and the Permian, we also have a natural gas-fired frac fleet operating in Canada. So we totally displaced the diesel up there. A number of our drilling rigs are dual fuel that can operate on natural gas as well as diesel. And so we're ramping up percentage of natural gas there. We're also looking to -- over time, we've eliminated a lot of the diesel fire generation that we're using out in the field and gotten on grid power there. So just across the portfolio, looking for ways to reduce the amount of diesel required our wet sand mines that we're using in the Permian and starting to use in the Montney, that eliminates truck miles. That's one of our biggest pass-through costs is when transportation has to pass through the diesel cost.

So it's really across the board. But by using less diesel, we have less exposure there. And again, any inflation we're seeing due to those diesel pass-through charges, we're offsetting that with efficiencies. So we've been able to do that successful year-to-date, and I think we'll be able to do that going forward as well.

Chris Baker with Evercore ISI.

Brendan, earlier, you talked about a pretty dynamic macro environment. Would love to hear how you and the team are just thinking about the 2027 growth option that the portfolio provides here.

Yes. Great question, Chris. I think the exciting news today is the growth with no capital or activity. So that's kind of the first protocol as we start to think about '27, but we are also continuing to think about when might be the right time to invest for growth? Premature yet to say for '27, Obviously, going to watch some water come under the bridge on the global fundamentals. I would say within that, we're obviously all watching the same news flow out of the Gulf. But we're also watching closely to see where is Chinese demand going to normalize. And that's a harder thing to know and be certain of, but going to be an important balancing factor as we think about the fundamentals for 2027, and beyond.

But really, again, our orientation will be around value, where can we create the most value and return on invested capital. And if that turns out to be growth, then so be it, we've created the inventory the processing capacity and logistics to be able to do that in both assets, but we will also weigh that investment against the buybacks that today continue to look really attractive from a per share perspective. So I think no change to our approach or philosophy just trying to make it with the best information we have on hand.

Great. And as a follow-up, just a lot of great questions already on the stack innovation. Just kind of putting the pieces together in terms of the higher plateau in the Permian. It looks like the type curve in the slide is pretty much unchanged. I'm just curious, as we think about putting together a shallower base decline and the type curve that you guys started the year with here, it does continued outperformance and the potential to revisit that type curve represent upside to the guide. Just trying to kind of put those 2 pieces together and how to think about when and it might make sense to revisit the type curve?

Yes. I think, obviously, the more data we accumulate, the more we study that. But for now, the guide makes sense, and it's the right go-forward way to model the company. But we're always looking for ways to improve it, and that's been the track record here, and we'll get to that in time as we work our way through the rest of this year and in the next. But for now, the guidance makes good sense. I think boosting it up to the 125 is the real value accretion for our shareholders, and we're proud to be able to do it.

John Annis with Texas Capital.

For my first one, the pacesetter Simul-frac operation achieved completion speeds of more than 7,000 feet a day, while the domestic wet sand pad reduced sand cost by 20%. My question there is how repeatable are these results? What percentage of the Montney program could ultimately adopt each and over what time frame?

Yes, John, thanks for the question. I'll pass over to Greg. But historically, our approach has been to think about those pacesetters as our target to convert to average. So the idea here is to -- for the team to be able to show, hey, if we can do it once, why can't we do it every time. And our track record has been able to do that pretty reliably once we set a pacesetter, we've been able to convert that into our average performance down the road. But Greg, you can dig in a little deeper there.

Yes, for sure. Starting with the Simul-frac. Really the only limitation there is pad setup and logistics. And so I would say almost all of our operations in the Montney set us up well for Simul-frac, and so that's something we're incorporating into the program.

On the wet sand side, in domestic sand in general, the only real limitation we have there is the local infrastructure. Domestic sand is relatively new in Canada. So the mines are just starting to ramp up. There is a lot of activity in that space. So I think over the next year or 2, you're going to see more domestic sand options. And then as they're putting in those sand mines, we're actually allowing them to save quite a bit of capital if they don't put in a dryer and just supply wet sand. So we're working with a number of suppliers in Canada to try to make sure we get ramped up to where we can get to 100% domestic wet sand. But realistically, that's probably '28-ish kind of time frame. It will take -- this year, we're at 50% domestic sand with a portion of that being wet. Next year, I would anticipate that growing. But we're still probably a couple of years away from getting to a fully implemented program like we have in the Permian.

I appreciate that color. For my follow-up, you've already organically replaced locations planned for '26 in both the Permian and Montney. How much additional opportunity do you see to expand inventory through similar technical work? And should we expect organic additions to continue offsetting annual drilling activity over the next several years?

Yes. I think the opportunity still looks fairly sizable. If you think about up in the Montney when we did the 2 acquisitions, Paramount and NuVista, we had about 900 upside locations that we were going to look to convert. We've only converted 130 of those. And so the opportunity looks pretty good there.

And then on the Permian side, similarly, the latest step change has been with the Barnett, but we continue to evaluate organically all the horizons in our acreage position to see if we can convert those into the premium bucket. So it's never going to be completely ratable. We're going to have to sort of work on those over periods of time, but it seems to be continuing. There doesn't seem to be a stop to it. So we like that cadence. And that, combined with the ability to do some of these smaller bolt-on deals at really attractive entry points, I think gives us a lot of confidence we're going to be able to maintain the inventory duration, if not continue to grow it a little bit.

Kevin MacCurdy with Pickering Energy Partners.

Apologies for kind of going back to the shareholder returns, but my question is maybe a little bit more on the mechanics of the buyback. In 2Q, your buybacks were impressive both in terms of the amount you were able to do and kind of the price you're able to execute that. I guess maybe how did you make that decision during the quarter? And how were you able to buyback at that price, which was lower than your quarterly average and any lessons you learned for the future?

Yes. Maybe I can flip it over to Corey here, Kevin, to talk about mechanically how we do it around blackout and the like.

Yes, Kevin. So as we go through it, I mean, we've got our ongoing forecast what we think our free cash flow is going to be, and we do tailor it based on what's happening daily. To the extent we're in a blackout period, we do put in detailed instructions ahead of that just to make sure we've captured opportunities that might otherwise not be available. So when you take those 2 into account and the biggest factor here is the appreciation over the course of the quarter helps the average cost compared to what we bought the shares back at.

So it's really just a combination of being in the market regularly and then also adjusting daily if there's something going on.

Phillip Jungwirth with BMO.

I'll ask another one on surfactants here, but just at $100,000 per well, you do seem to have a cost advantage versus others for utilizing this. I mean you do a lot of data sharing. So just wondering what you think is contributing to the lower costs? And then separately, are you looking at utilizing surfactants at all on existing base production, which has outperformed, although it sounds like it's more driven by remote operating capabilities that you mentioned?

Yes. Phil, great questions. The $100,000 per well has been part of the stacking process over the last several years. And just to give you the under the hood, what we -- when we started the treatment costs were in that $0.5 million of well range that we've heard about from other operators. And with our work process here, we were doing trials in the labs to figure out what surfactants we're going to have the right efficacy in the field. And by the way, some surfactants make productivity go down, was our big learning in the lab. So we'll be very careful about the chemistries that you choose to deploy at scale in the field.

So when we started $0.5 million a well, got some surfactants that we're delivering results in the lab, trialed them in the field, proved them up and then went back to the lab and worked on substitutes that would allow us to lower the costs. And that whole iterative journey has led us from that $0.5 million a well down to the $100,000 a well level just by finding chemistries that could give the same efficacy on productivity without the cost. And that, I think, has been part of the advantage. It does take time, of course, in a well-established protocol to do that.

On the base side of things, on the workover treatments. We've got a sort of a different formulation that we use on our workover side to enhance productivity that we think is yielding really competitive results as well, and you see that in our updated production guide with the base being one of the big contributors. So not necessarily the same surfactants that we use on the upfront, but a different formulation that we use on the workover because we think we're fundamentally solving a different physical challenge with the workovers than we are on the upfront wells.

So -- and then final comment, just to totally blow the question out would be that the one thing we haven't data traded is our surfactant stuff. So we've chosen to keep that 1 privilege to ourselves for now.

Okay. Great. And then most of your Montney margin comes from condensate and there has been increasing momentum around additional egress for oil sands. How optimistic are you here? And just how supportive could that be for long-term condensate fundamentals with demand pull from diluent being a positive tailwind?

Yes, it's a really good question and quite timely. So if we wind the tape back up to January this year coming into 2026, there really wasn't a lot of credible new oil sands growth projects on the table. There was a variety of kind of brownfield expansions that had been chugging along for the last couple of years. And since that time, we've seen just a dramatic shift in just a couple of weeks ago at Stampede, it was probably the talk of the town was how much oil sands growth was on the table in a credible way. And it's been really a combination both of those companies, putting those plans together, kind of making them compelling for their shareholders, and then the right policy support from the federal and provincial governments to create the egress auctions for that bitumen.

All of that to say, there now appears to be quite a list of shovel-ready growth projects in the oil sands for growth. And -- so if you think about it, for every 1 million barrels a day of bitumen growth, that equates to about 300,000 barrels a day of new condensate demand for diluent. And so we have never seen as strong a structural setup as we have in front of us today in Western Canada for condensate, which is fantastic for our business as one of the largest condensate producers in Canada. It's a really favorable tailwind for us going forward. We'll have to see how that unfolds. But our whole capital allocation and strategy in Canada for the last number of years has been focused on condensate. It's the only premium hydrocarbon product in Canada and it just looks to get more premium on -- given that backdrop.

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 that you please disconnect.

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2026 First Quarter Results Conference Call. As a reminder, today's call is being recorded. [Operator Instructions] 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 first quarter '26 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 our disclosure documents filed on EDGAR and SEDAR+. Following prepared remarks, we will be available to take your questions.

I will now turn the call over to our President and CEO, Brendan McCracken.

Thanks, Jason. Good morning, everybody, and thank you for joining us. We believe the strategic steps for an E&P company to generate differentiated value creation will be to build a portfolio with best-in-class assets and inventory depth, create a competitive advantage with stacked innovation and execution, demonstrate a proven track record of capital allocation to deliver superior and durable returns and combine all of that with a clean balance sheet. We are very excited to have put Ovintiv into the valuable position of delivering on all fronts.

Since 2023, we've increased our Permian and Montney drilling inventory by more than 3,200 locations. This inventory life expansion has been unmatched by our peers and leaves us with one of the most valuable inventory positions in the industry. We did it without diluting our shareholders and while increasing ROCE and substantially reducing debt. And all along, our team has continued to build on their track record of operational and commercial excellence, the evidence of which is observable in public data.

We make the highest productivity oil wells in the Midland Basin and in the Montney, and we do that as the undisputed cost leader in the Montney and among the top 2 lowest cost operators in the Midland Basin. We have also boosted profitability by strategically marketing our volumes to deliver high realized prices, lowered our cash costs and reduced our interest expense and overhead. I'm extremely proud of our team. They have shown tremendous resolve to build our business into a leading E&P. We are pleased to see the value of what we've built start to become recognized in the market, and we are excited because there is still a lot of room to run.

We've had a productive start to the year with the successful integration of the recently acquired NuVista assets, the sale of our Anadarko assets and the significant deleveraging of our balance sheet. We accomplished all this while maintaining our focus on execution excellence and delivering another strong quarter of operational and financial results. We believe stability has real value for our shareholders. We have fundamentally derisked our business and positioned ourselves to deliver durable returns for many years to come.

Since the inception of our shareholder return framework in 2021, we've returned $3.7 billion to our shareholders through $2.4 billion of share buybacks and $1.3 billion of base dividends. In early March, we introduced the next logical progression of our framework, designed to deliver substantial value to our shareholders while allowing greater flexibility. We committed to returning 50% to 100% of our free cash flow via dividends and share buybacks. In 2026, we began the year planning to allocate at least 75% of our free cash flow to shareholder returns.

The market has shifted dramatically since then with substantially higher oil prices than we expected. Even with our shares up strongly year-to-date, we continue to see a substantial gap between our share price and the intrinsic value of our business at mid-cycle prices. That said, with the higher prices and higher free cash flow, we believe it makes sense to avoid over-indexing on procyclical buybacks. We also believe it makes sense to take the opportunity to further accelerate net debt reduction.

So if oil prices continue to stay elevated, we would expect to be in the 50% to 75% range. But even then, we will still allocate more absolute dollars to share buybacks than we had anticipated at the start of March. If oil prices retreat, we will have capacity to be opportunistic with incremental buybacks, and we would expect to be back into the 75% or above range in that scenario. Again, regardless of price movements from here, our returns to shareholders this year are now anticipated to exceed our original plan on an absolute dollar basis.

I'll now turn the call over to Corey to discuss our financial results.

Thanks, Brendan. In addition to our best-in-class asset portfolio, our balance sheet is now stronger than it has been in a decade. With the proceeds from the Anadarko sale, we were able to significantly reduce debt. And as of April 30, our net debt was less than $3.3 billion or less than 0.8x leverage. Our remaining long-term debt profile has no maturities before 2030. We expect to realize over $80 million of annualized interest savings from the debt we've repaid since the start of the year. This includes the repayment of the 2026 and 2028 notes as well as the balance on our credit facility.

We also have significant liquidity of $4 billion, which enhances our resiliency and allows us to be flexible and opportunistic through the commodity cycle. We remain committed to our investment-grade credit rating and our recent transactions were viewed positively by the rating agencies. Our capital structure has been rightsized. Our leverage compares favorably to our peers. And going forward, we are operating from a position of strength. Our first quarter results demonstrate our continued focus on execution excellence and strong financial performance.

Our cash flow per share at $4.62 beat consensus estimates by about 6%, and our free cash flow totaled $634 million. We delivered volumes at the high end of our guidance ranges for each product, including oil and condensate production of approximately 225,000 barrels per day. Our capital investment of $605 million came in at the low end of our guidance range as did our total per unit costs. We recorded a $1.2 billion after-tax noncash ceiling test impairment that resulted in a loss in the quarter. The impairment was driven by weaker oil prices in the first quarter, bringing down the SEC 12-month trailing price.

At current strip pricing, we do not expect to incur further impairments. Maximizing capital efficiency and free cash flow generation is a top priority this year. As Brendan noted, the impacts of recent global events have increased near-term pricing. However, the impact on the fundamental supply and demand dynamics remain unclear. Our portfolio now has significant duration and capability to grow production. However, we believe it is still prudent to maintain our stay-flat program with level-loaded activity in both the Permian and Montney and that higher oil prices accrete to free cash flow.

We're not currently seeing significant inflationary pressure on our 2026 capital program outside of higher diesel costs. For the rest of the year, we expect to largely offset any additional cost inflation with operational efficiencies. As such, our capital guidance remains unchanged. Despite the higher royalty rates resulting from higher oil and condensate prices in our Canadian operations, which Greg will touch on more, we are maintaining our full year production guidance, including 205,000 to 212,000 barrels per day of oil and condensate.

Strong performance in both the Permian and Montney is expected to offset volumes lost to higher royalties. In the second quarter, we expect production to average approximately 623,000 BOEs per day, including about 203,000 barrels per day of oil and condensate, and our capital spend is expected to come in at around $575 million. Activity cadence in both assets is expected to be fairly ratable for the rest of the year.

I'll now turn the call over to Greg, who will speak to our operational highlights.

Thanks, Corey. I'm really proud of the efforts made by our operating teams this quarter. Through the integration of the NuVista assets and the sale process for the Anadarko, they never lost focus on safety and efficient execution. Our team is committed to continually improving our capital efficiency and our outstanding operational performance through the first quarter gives us confidence in what we can achieve through the rest of the year.

In the Montney, our first quarter well productivity was very strong and is tracking above our 2026 type curve. We hit our 85,000 barrels per day target in the first month after closing the acquisition, and we have been very pleased with the results across our acreage. With the NuVista assets now fully integrated into our Montney operations, we are focused on running a low-level program and offsetting the impact of higher royalty rates.

The sliding scale royalty structure is a unique aspect of shale development in Canada. As the name suggests, the percentage royalty that we pay slides up and down based on the prevailing commodity prices. So while gross volumes are unchanged, higher royalty rates mean our reported net volumes are reduced. On Slide 10, we've provided a simplified illustration of the production and revenue impacts across a range of oil prices. The key takeaway here is that although higher royalties result in lower net volumes, we are benefiting from higher prices where it counts, in revenue. This is a good problem to have.

If condensate prices were to average $90 per barrel for the year, we would see a 5,000 barrel per day reduction in reported net volumes, but a 40% increase in revenues. Although we don't like losing the volumes, this is a trade-off we are willing to make. It is also worth noting that condensate prices would have to reach approximately $135 per barrel before royalties would be in line with the rates paid south of the border, which are around 20% to 25% regardless of commodity prices.

Due to royalty impacts and planned plant turnarounds, Montney production in the second quarter is expected to be at the low end of our full year guidance range. While these turnarounds and royalty changes put pressure on our reported volumes, we continue to be very pleased with our well performance from both our legacy and the NuVista assets. Our 15 and 16 increased density test continues to meet or exceed our expectations, and we plan to test additional upside locations later this year.

Without the larger royalty take due to higher commodity prices, our total company oil and condensate volumes would be trending toward the high end of the guidance range for the year. Although the economics of our Montney wells are driven by condensate, it's important to note that our natural gas price diversification strategy continues to yield attractive results. In the first quarter, our Montney gas price realization was 175% of AECO. We continue to look for opportunities to secure both physical sales out of the basin and financial arrangements to price our gas away from AECO. We are exposed to AECO pricing on less than 20% of our 2026 Canadian gas volumes.

We also have a JKM-linked contract for 100 million cubic feet per day that began during the quarter, that essentially is in the money when AECO trades at less than 20% of JKM. The cash flow contribution from the arrangement was minimal in the first quarter, but at current strip pricing for the remainder of the year, it would be worth roughly $60 million. Overall, our Montney asset is performing very well. We are maintaining a repeatable program type curve. And despite some royalty noise, the program is delivering fantastic results.

Our team hit the ground running on day 1 of taking ownership of the NuVista assets, and they haven't looked back. We spud our first pad on the NuVista acreage, the Wapiti 602, just 2 days after closing the deal and are already achieving our cost target of $1 million in per well savings. This brings the wells on the NuVista acreage in line with our existing Montney cost structure and sets us up to achieve the $100 million in annualized cost synergies that we promised with the transaction. We're delivering faster cycle times, extending the lateral length on wells that were otherwise constrained by lease lines, savings on completions through the use of simul-frac and cheaper domestic sand and reducing wellsite facility costs by half compared to NuVista's design.

We've also fully integrated the acquired producing wells with our operations control center. This allows us to remotely operate the wells and apply the same digital workflows used across our Montney operations. The result is minimized downtime and lower production costs. We also see the potential for significant future savings from things like the ability to optimize our development plans given more available processing capacity and the opportunity to further optimize our base production with more integrated infrastructure. I'm very proud of the team and the efforts they made to integrate the new assets into our portfolio.

Our Permian team continues their track record of outperformance in the first quarter. With average oil and condensate volumes of 126,000 barrels per day, our most recent wells are exceeding the 2026 type curve. These results continue to support durable return generation across our 12 to 15 years of premium inventory in the play. We take great pride in our development approach and our ability to stack multiple innovations to create industry-leading results, which defy the broader U.S. shale trend of well performance degradation. As a result, we are consistently one of the highest productivity, lowest cost operators in the Permian.

Last quarter, we talked about the productivity uplift we have observed from stacking innovations like surfactants and our completion designs. We pumped them in over 300 Permian wells since 2019, so our data set is robust. Compared to a similar group of non-surfactant 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. At a cost of only about $100,000 per well, these custom chemical additives are highly economic.

But surfactants are only a part of the story. There are several other factors that have contributed to our improvement in well productivity, including our cube development and reoccupation approaches, stage architecture as well as the use of AI in our operations trained on our proprietary data set. The result has been greater than 10% improvement in our Permian oil productivity per foot since 2023. And this is while the broader basin is fighting a 2% annual decline.

In fact, using public data from [indiscernible], you can see that in 2025, our Midland Basin peers were delivering average well productivity in line with our 2023 results, while our 2025 wells continue to perform significantly better. Our recent Jefferies report highlighted our repeated annual improvements in type curve performance and ranked Ovintiv's oil productivity per well as the highest in the Basin. We said this for a while now, but we continue to see our culture of innovation as a real competitive advantage. It's not something you can buy. It's something that must be cultivated over time, and we are seeing it deliver tangible results.

I'll now turn the call back to Brendan.

Thanks, Greg. I'd like to take a moment to recognize our team for the safe and strong first quarter results they achieved and acknowledge their focus and drive to make our business more profitable for our shareholders. We delivered another strong quarter, meeting or beating our targets and delivering cash flow per share and free cash flow per share above consensus estimates. Our integration of the NuVista assets is complete, and we're generating free cash flow well in excess of our expectations at the start of the year.

Our track record of skating to where the puck is going is proving to be very valuable for our shareholders. Over the last few years, we've worked hard to high-grade and focus our portfolio, build extensive inventory depth, drive capital efficiency and reduce our leverage. Along the way, we demonstrated that we are disciplined stewards of our shareholders' capital. Now we are entering a period of stability where we can focus on maximizing the profitability and efficiency of our business. We're excited to unlock the full value of what we've built.

This concludes our prepared remarks. Joanna, we are now ready to open the line for questions.

[Operator Instructions] First question comes from Greg Pardy at RBC Capital Markets.

Maybe just a question for Corey to start is, with the action maybe on reducing net debt here on the balance sheet, are you moving the goalpost in terms of your optimal financial leverage? Or is this just being thoughtful around windfall cash flows versus purchasing stock right now?

Yes, Greg, thanks for the question. So yes, we're trying not to set a new long-term debt target. Obviously, we've been carrying that $4 billion target for some time now. So this is really more a choice of allocating capital and just letting cash build on the balance sheet. Over time, obviously, we'll look at opportunities to take out further debt, but we don't have that much cash at this point, but we gave an April month-end number. So it's about $400 million of cash on hand right now.

Okay. And Brendan, for the last few years, you just emphasized, look, the market is not looking for additional barrels to come on the market. Beyond the oil price escalation, which may hang around longer than we think, your increased focus in the Montney changes things because at the end of the day, right, Canada is short condensate. So my question for you is, as you look forward, is there now a more compelling case to grow condensate in Canada? Or has -- is what you're looking at just more temporary from an oil price and strategic perspective?

Yes, Greg, I think it's undisputable that there is a more constructive condensate fundamentals supply and demand dynamic that has unfolded here. A few things have happened at once. And I'll come back to the broader macro piece, but if we just touch on the condensate part that you've raised here first, we're seeing pretty strong growth coming out of the oil sands and with the prospect for more, a lot of egress projects being contemplated in Western Canada, which we obviously think is fantastic for Canada, but also for our business.

And all of that is putting pressure on the supply and demand fundamentals for condensate and driving that premium higher. That's already happened where we've moved from a market where condensate traded a few dollars back to now a market where it's looking more like parity to TI. And then I think as the dynamics unfold and more oil sands growth comes, we're just going to see more and more constructive condensate fundamentals. So that's the specific condensate part. I'll just touch briefly on the overall macro and how we're seeing that unfold.

A lot of dynamics, there's a number of signals that we're watching very closely today to try and assess how much duration in the more constructive oil macro are we going to see here? Because clearly, we've got some pretty constructive front month dynamics. So this isn't going to surprise anybody, but we're watching closely to understand when is the strait going to reopen in a real way. What might be the impact of those barrels that are currently behind pipe or in storage once that happens.

Also watching for what degree of demand destruction is underway here with these higher oil prices. And then watching closely for the North American supply response and the dynamics between OPEC and obviously, the UAE today as a former OPEC member, how are those dynamics going to unfold? And then, of course, in the major consumer markets, principally China, how are their demand picture going to unfold over time. So just a lot of different things -- factors that we're watching unfold, but certainly a more constructive macro than we expected coming into the year. And what we're looking for now is duration in that signal.

The next question comes from Doug Leggate with Wolfe Research.

Guys, I wonder if I could go to Greg first. Just a simple question, Greg, on the productivity comments you made. Obviously, all very impressive. We all see the data. What we're trying to figure out is, is this recovery improvement? Or is it bringing forward production to the extent you've got enough data to be able to make that call at this point? And then my follow-up, if you don't mind, Brendan, is for you.

And obviously, thrilled to see the shift towards putting cash on the balance sheet. I think you know our view on that. But I am curious to know, when you talk about share buybacks justified on value, you said you're still seeing a substantial gap at mid-cycle. What do you see as your mid-cycle free cash flow that stands behind that statement?

Okay. I guess starting, Doug, thanks for your question on productivity. I mean -- generally, we're just continued to be incredibly pleased with the strong well performance we're getting from both the Permian and the Montney. I assume you're referring to the surfactant uplift that we're seeing in the Permian. There's a number of factors there that cause us to believe that, that is not acceleration, but actually higher recovery.

The first proof point I would direct you to is the fact that we've been observing this phenomenon over the last 5 or 6 years. So we're seeing that uplift persist over a longer period of time. Not just -- it's not just a short-term uplift. But also, as a part of our surfactant diagnostic program, we've been doing a lot of work with geochemistry where we actually fingerprint the oil. And what we've seen in the wells that we pump surfactant in is we actually see a different oil come back. It's got a different composition.

And so that tells us that the wells being treated with surfactants are not only performing better, but the oil comes back slightly different. And that would point us to, yes, this is different oil. This is additional oil and not just acceleration. But all of that together tells us that we're doing something different, and it's been sustained over a number of years now. So we feel pretty confident in it.

And then Doug, I can -- Doug, this is Brendan. I can jump in on your question around mid-cycle pricing and the cash flows. So when we look at the intrinsic value of the company on a per share basis, we like to run that at our, albeit, what seems like today a conservative mid-cycle price of $55 WTI. And we've kind of had that as our mid-cycle price for quite a number of years.

And so we just think that's a good discipline to look at the business through, even though today, the supply and demand fundamentals would solve for a price probably more in the mid-60s. But -- so if we look at that $55 WTI, that implies about a $4 billion cash flow number for the business. And that's how we like to look at what's the intrinsic value, how are we trading in the market relative to that intrinsic benchmark.

The next question comes from Arun Jayaram with JPMorgan.

Brendan, you and the team have spent a lot of time making moves in the portfolio with some good trades to kind of really clean up and improve the portfolio with the core focus on the Montney and Permian. I was wondering, how we should think about portfolio management moves from here, just given where the balance sheet is going to be and the fact that you are kind of long inventory at this point?

Yes. Appreciate it, Arun. Great question. Really, we think about the business now into a period of stability where we can sustain that inventory depth that we've created. So if you think about some of the larger M&A moves that we've made over the last few years, that's not our focus today. So we're very excited that we've reached this kind of milestone with the portfolio. And today, our focus is going to be on driving incremental profitability. So we think that stability has got real value for our investors and pleased to have put that behind us, having to build this premium inventory position.

So it really puts us in a place now we're operating from a position of strength. We have the duration, and we can just focus on sustaining it. And I guess I would also say we've shown with our organic ground game, we've been able to replace that inventory on a really cost-effective basis as we go. So sitting here just with the first quarter behind us, we've already replaced our full year 2026 inventory consumption with the density conversion of about 130 locations in the Montney that we announced last quarter and then the Barnett position in the Permian effectively replaces a year of Permian consumption at least. And so we're excited to already be playing with a full deck for 2026.

And maybe a follow-up and maybe a housekeeping question for Corey. On Slide 16, you highlighted your guidance items in the deck, including your updated views on kind of current taxes in a higher commodity price environment. Corey, you still are very minimal U.S. cash taxpayer in '26. If we assume kind of strip pricing today, any thoughts on how cash taxes could trend in the U.S. in calendar '27?

Yes, Arun, thanks. We all love getting tax questions on the conference call. So I appreciate that. For the U.S., if you took this year and replicated it again next, we'd expect a similar level of cash tax. So pretty minimal. And then into '28, the company becomes more of a full cash taxpayer on the U.S. side.

Next question comes from Lloyd Byrne with Jefferies.

Can you just start maybe, Brendan, with this concept of stacked innovation and then why OVV feels differentiated in that? And then kind of what that means for capital efficiency going forward? I know you talked about -- or Greg talked about surfactants and AI and stuff. So how do we think about continued capital efficiency?

Yes. Yes. No, for sure. And we put stacked innovation as one of those critical strategic steps that you -- an E&P company needs to be able to hit home in order to deliver this differentiated value creation and -- and so we think it's tremendously important. We think that's been true for a long time, but it's becoming more and more true, particularly in North American shale because of the maturation of the resource.

And so the companies that can demonstrate that -- capability are going to demonstrate outsized returns, and that should imply a lower cost of capital and a higher valuation. So that's the buildup for why we think it's important. Really, what it is, is it's a long game. This is an industry where there is no intellectual property. There is no trade secrets. But there is the ability to create a lot of differentiation in whether you want to look at returns or capital efficiency because of the method.

And the method takes years and years to build up the learning and the capability. It takes a lot of work on the data side to build up the data to give you true causal results so that you understand by changing what input variable is controlling the output variable. And so what we've been able to do is build a culture and an expertise here that has created that institutional learning over a period of really years that allows us to run at the forefront of capital efficiency. And we take, I'll call it, an ambitious yet humble approach here. So we're, on one hand, very ambitious to try and lead in this industry because there's a lot of great companies doing a lot of great things. But we're also very humble because we choose to learn from what's happening around us.

So we've focused very hard to build a unique private data set that lets us observe not only the innovations that our team is making, but also the innovations that every other operator around us is taking and import those learnings into our system. You've heard me say the tagline here is the only infinite rate of return is learning from somebody else's capital. And so we've been really aggressive about doing that. And when you look at every indicator of how that's turning out for us, whether it's the well performance results, whether it's our cost results, you look at the innovation pipeline of ideas that we've got running in the company today.

You look at our data trade numbers, the knowledge shares that we do, the predictive models that we've built, they all point to Ovintiv running at the forefront of the industry on an efficiency basis. So we make the highest oil productivity wells in the Midland Basin. That is not an easy thing to do. There's a lot of great companies in the Basin doing a lot of great work, and we're proud to have achieved that. We make the highest oil productivity wells in the Montney.

And we do that while being the lowest cost operator in the Montney and amongst the 2 lowest cost operators in the Midland. So I think that's a long way of saying this is a whole series of activities and capabilities that we've built up over years and years that are now showing up in the results.

And I guess -- is there one technology or change that you're still most excited about from here?

Well, in the rearview mirror, the technology that's yielded a lot and has gotten a lot of market attention has been the surfactants. If you look at our well performance data over the last several years in the Permian, we're up 20-odd percent on a per foot basis for oil productivity and about half of that is coming from surfactants. So that's the rearview mirror.

I mentioned this innovation pipeline that our team continues to try and fill up. And remember, it's not just the ideas we generate, but it's the ideas that are being tested and tried all around us that we're learning from that fill that innovation pipeline. We've got a number of other things that we're excited about deploying and testing over time. But I don't know, Greg, if you want to add anything to that?

Yes. I think it's a combination of improving well results, but also improving costs. And some of the things that are exciting on the cost side is, we continue to pump down more than one well at a time. We continue to pump more hours of the day. We continue to pump more sand than our peers, but we do it for less cost because it's local sand in many cases.

So it's just -- as Brendan was saying, it's a combination of all of these things. If you start at where we are today and try to imagine how to replicate our performance, it would be very challenging if you hadn't walked the path that we've walked over the last 5 to 10 years. So lots of things have added up. There's still things in the hopper. We're not done yet.

And I think one of the things you've seen us pointing to and showing off on some of the investor tours we've done recently is our AI capabilities. And that, of course, is the big technology frontier here to use AI, pair it with that private data set that we've built, develop those in-house algorithms to deploy, whether it's in our production operations centers that are driving uptime and artificial lift optimization or whether it's in our frac designs and tuning the 70-odd input design factors that go into each frac we pump on a real-time basis. So yes, the innovation pipeline is as full as it's ever been and excited about continuing to bring those into the field.

The next question comes from Neil Mehta with Goldman Sachs.

Brendan and team, I guess this is the last time we did a call -- the earnings call, which was only a couple of weeks ago, we have had a large deal in the Montney at a significant premium. And just without commenting on the specifics of that specific -- that transaction, I'm just curious what you think that means for the way that you're thinking about the value of your Canada business?

Yes, Neil, I appreciate the question. Yes, you're right. Look, I think it continues to highlight the recognition that we've been pointing to with our actions and how we've been describing the Montney, the capital is starting to be allocated globally towards the Montney, not a surprise there. We weren't involved in that transaction in any way. We had already skated to where the puck was going there with the 2 larger transactions we've done in the Montney oil window to build the premier position in the oil window of the Montney.

So we welcome the flow of capital and the recognition. And obviously, there's -- I think it's another way to point at the valuation gap that we see between the intrinsic value in our company and where our equity trades at. And so it's another way to triangulate and look at the read-through of what was paid for that other company, combine that with how Permian trades and you get a lot higher number than what's on the screen today for OVV.

Yes. No, that's helpful. And just a follow-up is -- on NuVista integration. Slide 11 is helpful for us Wall Street folks. Maybe you can just explain that Slide 11, the optimization of the pad and how the changes in design are translating into results.

Yes. I'll turn it over to Greg. It's a pretty compelling story just to set them up. That pad we took over 2 days after it was spud. So kind of really real time at closing, and it's pretty incredible achievement by the team to do what they did there. But over to Greg for the details.

Yes, I really appreciate the question and the opportunity to kind of dive in a little more. Kind of starting with just the map up on the top right, what we were able to take advantage of by combining these 2 acreage positions, we could take what were going to be fairly modest length laterals and extend them down into our acreage position. And as we all know, longer laterals yield better cost per foot.

So -- and this is just one of many opportunities. If you look along that lease line, you can see lots of opportunity to extend laterals from the NuVista lands over into our position or vice versa. So we were able to lengthen the laterals. We were able to tie in the wells to our DRIVE Center that some of you may have toured when we were in Calgary last year. And that's our -- basically our real-time drilling optimization center. And so we were able to take all the results in from the rig, optimize those in real time and drill those wells a couple of days faster than NuVista was planning on drilling them at similar lengths.

So we were able to drill faster. And then we were able to incorporate some of the techniques we've been using for a long time with local or domestic sand and simul-frac. We were able to pump those wells faster than you would normally have done. And all of those add into savings. And then finally, we were able to implement our facilities design. We use a much simpler facilities design than NuVista was using. So we're saving about half off of the facilities cost.

So just a great opportunity for the team to demonstrate what we promised when we announced the acquisition was that we would get to our well costs very quickly. So we budgeted that way. And on this very first pad, we're delivering at or below the well costs that we were planning on. So just a great execution by the team, really strong integration effort to hit the ground running just days after the acquisition closed.

The next question comes from Gabe Daoud with Truist.

I was hoping we can maybe go back to the Permian. Brendan and Greg, I guess, specifically, how much of the program this year is pumping the surfactants that you highlighted? And then just also curious, just given the outperformance that you've seen with your curve this year, would it be premature to think that your 205 to 212 oil and condensate guide could be maybe tightened or biased higher? I know that there's some headwinds with the royalty sliding scale in the Montney, but just curious how you think through that.

Yes. Maybe I'll start with the second question, and then Greg can pick up the surfactant line. But Gabe, I think the great news is the early wells of the '26 program are really strong in both the Montney and the Permian. And we're not changing how we're planning the business at this point. So the type curve for 2026 still holds, but always really nice to play with the lead. And so the team has done a great job of that through the first quarter, and we'll watch how that goes through the year.

But we know the direction of travel that's happening industry-wide. And so what we wanted to point to with the results is, look, investors should feel really confident in this message that we've had for quite a while now, which is, we're going to be able to outperform and create differentiated results because of the work that we've built into the system here. So great to see the positive signal, but we haven't changed the long-term type curve plan for the Permian.

But over to Greg on the surfactant.

Yes. As far as our application of surfactants, we've really advanced our approach here over the last several years. If you were to go back in time, initially, we were only pumping on a small number of wells. Our costs were something we were working to bring down. But we've worked to really hone in on the right formulas for the right zones. We've gotten our cost down to $100,000 a well.

And so just for kind of walking through the last few years, in 2024, it would have been about half of our wells got surfactant treatment. In 2025 or last year, it was about 75% of our wells. And this year, it will be -- almost all of our wells will be treated with surfactant. We're still toying around with a few zones, the Barnett, for example, I'm not exactly sure what we would pump in that yet when we do that later this year. But almost all of our wells will get surfactant treatment, and we're doing it at a very low cost. And as we've talked before, seeing very solid uplift there. So -- but it will be essentially all of the program.

Got it. Got it. Okay. That's helpful. And I guess just as my follow-up, your D&C per foot is pretty attractive in both plays. And I know historically, you would also highlight what the pacesetter is in both plays. So, I guess, just curious on what that number might be today. Again, I know there's maybe some inflationary pressures that could be down the road, but nothing today. So curious what those pacesetter wells maybe look like on a D&C per foot basis and then maybe a reasonable expectation around when the pacesetter becomes the play average?

Yes, I'll turn it over to Greg, but that's a good example of this innovation pipeline and action. So we love the pacesetters on the cost side because they tell us what's possible. And then we go and chase that to make what's possible, the average outcome. And so, yes, over to Greg on what we're seeing there in terms of days per foot -- feet per day on the frac and drilling side, giving us some confidence there's still room to move on the well cost side.

Yes. It's a great question. This is something we're always watching. We continue on both sides of the border to both drill and complete our wells faster than we ever have before. We're continuing to drill. And it's gotten to where it's harder to take off days and weeks like we used to be able to take off, but we're still seeing improvement on the drilling side. We've had -- the last few quarters have been some of our fastest quarters.

But we are working to offset. There's a little bit of inflation in the system right now with diesel cost being mainly pass-through diesel costs. So I would say that we're continuing to trim half days and days off the drilling side. We're continuing to trim days off of the completion side. And today, that's got us comfortably saying we're still below $600 a foot in the Permian and $500 a foot in the Montney. But if we continue to have those faster cycle times as we see the inflation, we think, ease a little over time, then that will start translating in lower well costs. But right now, we feel very comfortable with the guide that we have out there today.

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

I wanted to ask about how you see the production growth optionality in the Permian now? It's an asset where you have low to mid-teens inventory life. It's a good runway, although not quite at the Montney levels. With the ability to grow the Montney 5% plus, what's the scenario where you'd also look to grow the Permian? And could a higher plateau than 120 a day of crude and condensate make sense, noting that I think you're at 125 in the quarter.

Yes, Phil, thanks for the question. I think we'd see the option to grow in both places pretty much the same. I think if we went to growth, which we thought long and hard about here, we would likely do it in both places. The return proposition is the same in both, and we have the capability from -- as you said, from an inventory position in both. So we do think that is a very real option.

We're saying today, we're going to be patient and watch the macro unfold a little bit longer here, but we do have the option in both places, and we worked hard to build that capability over the last several years. So in the meantime, we're just going to continue to lean in on performance to generate upside barrels in this price environment and watch how the macro unfolds.

Okay. Great. And then you noted earlier, the stock still trades below intrinsic value. I think most of us would agree with that. S&P is considering adding companies not domiciled in Canada to the S&P/TSX indices at reduced 50% weighting. Wondering if you've looked at this or have any thoughts as it relates to Ovintiv and expanding the investor base up north just because being in the bench can help, but there's obviously a fundamental element to the story here with having a leading Montney position and Anadarko going away.

Yes, Phil, I think the combination of those fundamental improvements to the business, which we've spent enough time probably harping on today already, so I won't reiterate again, but the combination of those with that potential index inclusion would be quite constructive. We've seen the S&P reach out to investors for comment on that concept. And obviously, we're enthusiastic supporters of it. So we'll keep our eye on that one. But I think the more important part is the fundamental appetite to own the shares is strong today in both Wall Street and Bay Street, and we're seeing that in investor sentiment and interest.

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

Apologies for staying on the subject of growth and shareholder returns. But my question is maybe about the calculation here. In the past, you've seen value in buying back your stock versus growing production. My question is, is there any update to how you calculate when you're deciding between those 2 uses of cash? Are you using the strip? Are you using mid-cycle prices? Kind of how do you calculate that?

Yes, Kevin, good question. We've been looking at it across a range of prices. That's kind of been the approach over the last several years to look at that. And really, the fundamental intention we wanted to create is cash flow per share growth and the most efficient cash flow per share growth. And -- what I'd say, and we had said for quite a number of years is that calculation kept telling us the buybacks were more efficient.

Today, that's moved much more into a balanced position. So today -- and again, it does depend, which is your question on which price, which oil price to use. But even at a more modest oil price, that relationship has moved more into balance. So it opens that door a little more than it was the last several years. So we like that. It creates a real option for cash flow per share growth value creation for us.

Appreciate that. And maybe as my follow-up, I'll shift gears to OpEx. Upstream T&P was much lower than the guide in 1Q. You chose to keep your 2Q to 4Q guide kind of intact. Can you talk about the moving pieces there of that line item in light of all the transactions that happened in the first half of the year?

Yes, for sure. I'll take that one, Kevin. So I guess the first thing I'd say is Q1 really is just a bit noisy on T&P. So a couple of the puts and takes there. It included our Anadarko volumes, which have a lower T&P rate. It includes some, but not all, of NuVista. We didn't have NuVista for the whole quarter, which is going to be at the higher Canadian T&P rate, which is similar to our other Canadian assets. But we also had some onetime adjustments in the quarter that were in our favor.

So that really just ended up pushing down T&P to lower than our normal run rate in Q1 is the way you should read that. But going forward, our T&P is right in line with what we've expected. So if you kind of think about it holistically, Canadian assets typically have more of their cost in the T&P side of the structure, whereas U.S. assets, it's more on the LOE side. So going forward, you'll see LOE come down or OpEx come down. T&P will be up slightly. But all of this is very much in line with what we've expected all along.

Next question comes from Neal Dingmann with William Blair.

Probably for Greg. Greg, my question is on the Permian plan this year. Specifically, I believe you all targeted around 125 to 135 wells. Will most of this continue to target Wolfcamp and Spraberry? Or are you targeting some deeper zones as well like the Barnett?

Yes. Thanks for the question, Neal. Yes, pretty straightforward program. We've got one Barnett well in the program. So the rest of the zones we'll be targeting will be the normal stack going from Spraberry, Dean, Jo Mill, all the way down through the Wolfcamp. But no real exposure to Barnett other than that one test we're doing this year. And that's really, as we've said before, we find our Barnett acreage interesting. But we don't have the same maybe drivers as some peers and that our Barnett acreage is held by production.

So we're going to kind of take a slower approach. We really like the productivity of the zone, but it's the cost question that we're still trying to answer. I think over time, we'll see as others and ourselves learn more about the zone, we'll get better, we'll get faster and we'll get cost down. But this is a great opportunity, it is like Brendan was alluding to earlier, learning from peers, this is a great place where we can learn a lot without spending dollars. So we'll be watching our peers and learning from them on the best ways to drill these Barnett wells cheaper.

That makes sense. And then just secondly, on marketing for the gas specifically, in the Perm, are you seeing near-term power opportunities or anything you're considering there?

We constantly look to try to lower our OpEx there. But as far as engaging in another line of business around generation or power, if that's what you're alluding to, that feels beyond scope for us today. But we're always looking at innovative ways to lower our -- both our OpEx and generate power for our electric frac fleet as cheaply as possible. So we're looking at interesting things there, but probably narrower scope than what you might be referring to.

And the last question will come from Chris Baker with Evercore.

I thought I took down my hand, I think all my questions have been answered, but I appreciate the time today.

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 that you please disconnect your lines.

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. [Operator Instructions] For members of the media attending in a listen-only mode today, you may quote statements made by any of the alternative 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 the 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 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 disclosure documents filed on EDGAR and SEDAR Plus. 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 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 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 balance 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 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 match 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 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 reduced 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 impact 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, Cory. 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 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. And 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 the 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 seven 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 pay set 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 over 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 and 1 to 2 frac crews, bring 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 loss 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 or 16 pad, we added a third bench and increased entity 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 and a 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 it mine back for questions.

[Operator 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, we'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, you've set a wider range. And really, the thinking here is we want this framework to be durable through the commodity price cycle. And in particular, we want to avoid setting up a procyclical framework, and 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, if you will, when commodity prices are well above mid-cycle be banking that windfall permanently into the capital structure. And 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 surfactant 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. It looks to be driving some 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. And 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 because we felt like we had kind of got out ahead of others in this space and that's what you're seeing 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.

Yes. Thanks, Brendan. And thanks for, for the question. And 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. So maybe just a little bit about what we're doing. So these surfactants that we're pumping, there are liquid additives that we include in our frac fluid that are designed to improve oil recovery in the reservoir down hole. So once you pump them down hole, 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.

We've been working for a number of years on this, both in the lab and in the field. So we've done core testing in the labs as well as field trials to try to determine which surfactants work best and 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. And so far, 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. So we started out in the early years with some field trials gain confidence. And more recently, last year, we pumped surfactants and about 75% of the completions we've pumped in the Midland Basin and saw very good results with that.

We would anticipate probably a smaller amount this year in 2026. So we've 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. But the continue -- the team continues to experiment with this and will continue going forward. But 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's going to -- it has been and will continue to be a big reason for 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?

Yes, so this is an interesting question. So 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 and when our lab work has really let us do is trial hundreds and hundreds of district 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. So Greg commented on one of the things we've been fine-tuning is the amount of surfactant that we've been pumping, but the other feature has been substituting cheaper and 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 an 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. So really appreciate that, Lloyd. With this latest transaction, we pointed to is $100 million of synergies, but we also pointed to several synergies that we didn't quantify at this time. And we think those are going to show up on the infrastructure side. We saw that with the Paramount integration. And really, now we're kind of stitching together our legacy infrastructure, the Paramount infrastructure and then now the NuVista infrastructure, all 3 of those overlap. And so there's 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. And then there's going to be some organizational synergy 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. And so I do want to recognize their effort and the results that they have delivered. And we've taken big steps to simplify the portfolio, and so we will be redesigning our organization to match that new portfolio. And 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 looks activity -- looking like maybe, right, about 1/3 of activity coming from the NuVista 1/3 Paramount and the 1/3, the prior position. And I'm just wondering if so, do you anticipate sort of similar activity across the board and are those well results pretty similar across the board.

Yes, Neal, you got it, Neal. That's about the activity cadence going forward is going to be that 1/3, 1/3, 1/3. And and just a quick comment on the driver for that. That's really an outcome of our reoccupation strategy. And 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. So 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. And so that is a governing feature of our development programs. And so that in those small part drives that allocation of activity as we just continue to [indiscernible] the yard across our acreage position in both the Montney and the Permian. So that's the big driver of that piece there.

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. And 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. And 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 old cube at the same time, and that's worked quite well for us. So no major changes there.

The next question comes from Neil Mehta with Goldman Sachs.

Yes. Brendan, congratulations on, again, this transformation over the last 5 years and maybe that's kind of the key question for me, which is, have you gotten the portfolio to the optimal level where you -- I think when you took over, you were in 6 areas, now you're at 2. Are you in your sweet spot? Does that mean that 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?

Yes. Thanks, Neil. Yes, the portfolio transition here is complete. So we've clearly planted our flag in the Montney in the Permian, where we have competitive advantage and where we see the best resource. And we've built one of the longest duration inventory positions while we did that. And so 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. 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 that's just the pro forma portfolio. And then Q2, you've got a little bit more maintenance in Montney. So 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. So a little bit higher capital in Q1 is absolutely just the Anadarko effect. And so once we close that, that will come out and we'll just run rate out and I think we've probably said transition or transformation, the highest word count on the call so far. But 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. And really, we've got that as a really key feature in 2026. So we really like how we've leveled out that and it just creates 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, in 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 really excited about the the evolution that's going on in the Montney as we shift more and more to domestic and wet sand in the Montney 2. And this is another great example of stacked innovation, creating value for us. And 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. 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. And so 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. 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. And so we've been 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. And this year, we're going to have roughly 50% of our sand pumped will be domestic sand. They're sourced in Canada. So you eliminate that rail [indiscernible], and you were 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. And that is an evolving technology that we think we're going to be able to use more and more over time. So 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 stay with Montney now. When you kind of compare and contrast NuVista versus the Paramount acquisition. Can you -- how do you look at perhaps the degree of low-hanging fruit cost synergies, efficiencies and things like that. I think, Brian, in the past, you've mentioned Vista was actually a pretty good operator. I'm just curious on the two.

Yes. I think -- I mean, I'll start with geography first and then just come on to -- Greg will have some comments on the integration. But the NuVista piece really fills in the jigsaw puzzle. And so with Paramount, we stepped further south than we had been with our legacy, not by a long ways, but -- and we were, I think, 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. And so we stepped our way in a very thoughtful integration process through really a full year here. And 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. And then with -- in contrast, NuVista really filling in the jigsaw piece in between. We just have a lot more technical confidence and we're kind of integrating quite quickly with that piece. But Greg, if you want to comment on some of the specifics about how it's going.

Yes, for sure. Yes, I think Brendan set it up really well. It's going to be the same process on NuVista as it was on impairment. Paramount, it's just going to go a little faster. So 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 doable. So the team is already hard at work, employing the same playbook that we've used on all the LAP transactions. We came in day 1, I took over the asset. We had a short safety orientation, and they got to work. So by that afternoon, we were operating the asset as vented. There'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 to minimize downtime. We've linked the drilling rigs to our Drive Center, which is our optimization tool where we use AI to help optimized drilling performance, and that's going to allow us to deliver our synergies here very quickly. We've already incorporated the $1 million per well of savings the synergy savings, or what you're seeing as part of the guidance. We're going to be delivering that from day 1. And so, so far, we've had really, really good results. The teams are integrating well. The new wells remain drilled as expected. As I mentioned earlier, production is already at 85,000 barrels a day, which is what we expected for the assets as they come together. So integration is going quite well. Just really, really pleased, and I think it will be very similar to the last time. It 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 out with the transition of the Paramount integration of the Paramount assets. And so that does move 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 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 level of debt for you guys going forward? Should we think about it as kind of an absolute level or a net debt level to kind of think about free cash flow allocation?

Yes. Hi, Josh. So yes. So we've reached that target. In fact, we're going to move past it here with the Anadarko proceeds. So really, we're not setting a new target here. If you remember, the 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. So 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. And so 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. And at the same time, we put the inventory into a really strong and resilient position as well. So it just means we're in a place here now we can focus on keeping the debt around this level and focus on allocating more cash returns. So that's how we're thinking about the debt level going forward.

Got it. And then from a month operating perspective, I know you guys on the Paramount transaction, we're able to kind of optimize the infrastructure a bit more. talk about what you might be able to do on the NuVista asset as well to kind of 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 one 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. And so in the short term, we're really focused on getting the well cost savings at the well level putting in our completion designs, our facilities designs. And that's going to 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. So 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. But over time, that's something we're going to target to get our G&P down to get the gas molecules for the most efficient plant and work through those things. So that's coming a little longer. But 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 will be something we'll start working on here immediately.

The next question comes from Doug Leggate with Wolfe Research.

Brendan, I wonder if I could ask you about asset duration, and how you sign 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 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. I mean we haven't been exotic with our thinking there. We just run it off of what it takes to sustain the production. And 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 and this, again, 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 really derisk our inventory duration over time. And just as a refresher here, because we're designing our annual programs with that reoccupation in mind, so to come back sort of 12 -- sorry, 18 to 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. So 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 the worst locations for a decade from now. We're kind of drilling the full cubes and then reoccupying cubes as we go. So I believe that to be a big derisker. And 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, but we're delivering leading results we're doing that. And I think that's the true differentiation.

I appreciate that answer. I know it's a bit nuance 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. But I want to ask you about your philosophical view as the 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 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 is up 22%. Oil is about 70% for reasons we all know are not necessarily fundamental. And this is the year you're going for 75% of your free cash flow per share buyback. Why are you not choosing to be more discretionary in your timing?

Yes. I'm going to try and not be -- I guess I mean it's still trying to be humble here, but 30% still doesn't get us to what we think is a reasonable valuation for the stock. So I'm not trying to say that, that's not great, and we're pleased, obviously, with the momentum, but we still see a lot of intrinsic value in the equity today. When we talk about trying to avoid being pro-cyclical, a lot of that is going to be tied, as you know, Doug, to the commodity environment. And today, we're not in a commodity environment that screams really high windfall situation, I think, still in a relatively modest commodity environment today. And so we do not see the risk of being at 75% as opposed cyclical risk today because of that intrinsic value gap, we still see any 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 sharing the details on the correct job. That third zone has been an opportunity in the area. It sounds like you guys have cracked the code. And then where in the basin next do you plan to apply that design? And could the balance of the upside locations move into the derisked in-store account this year?

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

Sorry, I forgot to turn my mic on. Yes. So I appreciate the question. And we're really, really pleased with the results there on this 15 to 16 pad down in car. So 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. So this is the first pad that we really got to design to end in the area. And so we kind of met in the middle with 14 wells per section spacing. So we added that third zone down in the Lower Montney or the exit some call it. And and also increased density in the upper part of the cube up 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. And so far, we're really pleased. The pad has been online a little over 100 days. The lower zones actually exceeding expectations of what we were expecting. And then the upper zones are holding up very nicely despite the increased density. So our plans now are to move to other parts there of car 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 proves up 130 of those. So the next step will be to go to other parts of car in testing the third zone. And then we've still got work to do opt in other parts of the acreage. So 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, we still have a little more upside potentially up to 16 wells per section on a few of the pads. So really pleased. I 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.

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 turnaround is needed? And should we expect better performance from these plants and maybe that's a 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, maybe upgrade a few of the vessels. So 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 going to happen next quarter. What we're experiencing in this coming quarter as we just happen to have five of them, which are all lined up at the same time. And so normally, we don't really have to talk much about these because you may have 1 or 2 turnarounds going on at the same time and you can move volumes around. But when you end up having five at once all lining up at the same time, it just takes a little more coordination. So 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. But 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 to 87,000 barrels per day in the Montney. But 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. So I don't think this is a longer-term risk for us. This is just something the way the stars line. 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. So 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.

And Greg, just to follow up, coming out of maintenance, could there be any increase in the performance in those plans, maybe that's in yield after that work is done?

That's going to 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 changing oil in your car, it probably isn't going to run a whole lot better after you're done, but in some cases, we could see some minor improvement or flush production. But for the most part, this is just routine maintenance routine work that they're doing.

The next question comes from Betty Jiang at Barclays.

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

Yes, this is great. But again, I'll turn it to Greg. Here -- the headline here is we are being an efficiency gain on the well cost side. So we down on the well costs year-over-year and then holding the type through flat. So 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 -- 2026 that are kind of masking that a bit here, but Greg can cover that.

Yes. So thanks for the question. And so as we've been talking about today, we really like to usually run our programs on a very level loaded basis, at least that's been our goal. We've tried to complete our wells as soon as are drilled. So we don't very excessive DUCs. But as you might recall, last year, we had a number of extra DUCs coming into the year. So in the first quarter of '25, 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, and the only -- we only saw the completion capital last year. And 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. So really positive for last year. Unfortunately, for the metrics, we don't have that same circumstance this year. But we do have a very level loaded program that we feel very good about. It allows us to become more efficient and continue to execute very repeatedly when we do the same number of completions, same amount of capital, same production every quarter. And so you think about the building blocks of the guide, you've got a slightly lower cost per foot same type curve. So really, the only difference is the timing. And so that's what you're seeing manifest as it rolls through the numbers. But over time, we feel like this is going to be a very efficient program that's going to continue to get better over time as we continue to drive down the costs and keep that type curve flat.

For the clarification there. My follow-up 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 real cross in viability there?

Yes. I think I'll say Greg up here, but what we found and understood really from the early days of this is every bench in each county are going to perform a little bit differently depending on the wettability and the fluids that we're trying to impact. And so -- and the Montney does have 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. Some of it is looking like other pieces that it can add to the performance that we're seeing there. So it will be a little bit different. We're quite a ways further advanced on surfactants in the Permian with 300 wells pumped there. We've done no renew that many in Montney to this point, but really excited about completion design in Montney generally. We'll see surfactants were going to go a little slower there just because of the temperature and pressure differences. But Greg, over to you.

Yes. So yes, we're in our seventh year of surfactants in the Permian. And so 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 or most effective for the lowest cost. And so 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 assets. So 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. And so -- we're just -- I would position it more as we're just getting started up there, but the whole toolbox is available to us as we see that working as well as we see higher completion intensity, stacking and spacing optimization, all the things that we do in the Permian, we do the same in the Montney. And so we'll share those learnings across border, but maybe just a little earlier stage in the Montney on surfactants. And it will be a slightly different setup just because of the pressure regime downhole and the rock fabric. It's just a different reservoir, but we'll work to see if we can make the same kind of improvements there that we've seen in the Permian.

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

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

Yes. So we've been very interested in the Barnett and have 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. So we're watching as some of our peers are derisking the cost side as well as the well performance. We do have a meaningful Barnett position. We've got more net rights on about half of our acreage position in the Permian, so 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 going to watch and I think be prudent on how much we lean into the Barnett. It's a deeper horizon that's separate from our cube, so that resource is still going to be there later. It's not going to be impacted by the shallow production. So I think this is one where we have time to be a little more patient, but also have the ability to fast follow and go execute on that 100,000 acres if we choose to do so.

Okay. Great. And then 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 and Ovintiv supplying that versus maybe incremental equity volumes for the partners and more hypothetical, but would changes in ownership across the facility have any implications for Ovintiv or open up any strategic partnership or marketing opportunities?

Yes. So I think -- so 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 start-up that it's been at that level. So it's been a slow grind upwards with a bit of ups and downs along the way, as I'm sure you followed. So I think our caution on AECO remains the total takeaway from LNG Canada, while it's great to see it in recent time, up to that level. It's still relatively small relative to the total productivity potential of the basin, and we've seen the sort of behind pipe volumes, if you will, able to fulfill that takeaway. So 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. So yes, we continue to be interested in building out a diverse portfolio of markets for our downstream gas and 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. But I would expect 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. 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?

Yes. Appreciate it, Kevin. I think the two things that we've talked about with respect to growth are still very much in place. So the two dates, if you will, are -- do we see a fundamental call for incremental barrels or BTUs. And again, we don't see that today, the market's not begging for companies like ours to bring more volumes into the market. So that's kind of gate number 1. And then gate number 2 is can we create more cash flow per share growth out of share buybacks or out of incremental rigs. And today, we see that equation tilted towards the buyback. So we get a better cash 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. So the combination of both of those two gates today are telling us to stay in maintenance mode. But I appreciate your question because it surfaces the other aspect of the portfolio transformation that's important here. So not only have we added tremendous inventory duration, focus the portfolio, we've also unlocked growth potential. And at some point in the future, those two dates will call for growth, and we've now created the capability to do that very efficiently at high return for our investors.

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 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 from a well count perspective or a TIL perspective, almost a balanced program north and south.

Yes. You got it, Dennis. So that ground game has been really effective for us. Obviously, a lot of focus on the larger transactions, but the ground game has been grinding away very efficiently. And you think about where we've arrived at here, we've put the transaction risk of having to build inventory duration behind us. And now we can rely on that ground game, which is very efficient, low-cost way to sustain our inventory duration. And it just is sort of funded within our framework, within the balance sheet that we've got today. So we can just sort of put that in and let it opportunistically pick away as we go along here and sustain the inventory depth that we've created. So we like that feature, and we're 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. And the outcome is, like you said, a relatively balanced TILs, north and south. But it's really more designed to hold the production flat.

I appreciate that. Shifting on to innovation. There's obviously a lot of questions today focused on obviously use of surfactant, and obviously, your teams have done a very good job in terms of applying 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.

Yes. I know we love that question, Dennis. And really, this is our -- one of our mantras here is the only infinite rate of return we can generate is by learning from somebody else's capital. And what better way to do that than in an integration where you have full transparency and data and everything, but I'll put that to Greg because there are several things that we've been excited about from the NuVista team.

Yes. We were really pleased with the NuVista transaction. 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. So 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. So we're already working with them on how do we take some of those ideas and then using more broadly across our portfolio, incorporating with our operations control center and really up in 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 to the meter, to the foot where you're going to land the wells and 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. So we're implementing that into our program, and we think that's going to help us even improve quicker in Canada than we have been so far. So 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 what can we tell you we know. And so far, we're learning some from them, and it's going really well. So we're really pleased with that.

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 the conference call for today. We thank you for participating, and we ask that you please disconnect your lines.

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2025 Third Quarter Results Conference Call. As a reminder, today's call is being recorded. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Ovintiv. I would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.

Thank you, Pam, and welcome, everyone. 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 our disclosure documents filed on EDGAR and SEDAR+. Following the prepared remarks, we will be available to take your questions. limit your time to one question and one follow-up. 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're excited to talk to you today about another great quarter and some significant strategic actions we are taking to crystallize our vision to becoming the leading North American independent E&P.

First, we've entered into an agreement to acquire NuVista Energy, who have built an incredible asset base in the core of the Alberta Montney oil window. This transaction is priced right, and we expect it to create exceptional value for our shareholders. It is immediately accretive on all financial metrics, highlighted by a 10% boost to our go-forward free cash flow per share. It's leverage-neutral at closing, it comes with valuable spare midstream capacity and valuable downstream gas price exposure and it adds significant inventory in the high-return oil window of the Montney.

Second, we plan to commence the divestiture process for the sale of our Anadarko assets. Proceeds will be used for accelerated debt reduction, and we now expect to be below our $4 billion debt target by the end of 2026. That will enable us to allocate a higher percentage of our free cash flow to shareholder returns.

Third, we have continued to meaningfully add to our Permian well inventory at highly attractive prices by prosecuting our ground game strategy in the Midland Basin. Finally, we continue to deliver exceptional performance across the organization, highlighted by our strong third quarter results and positive full year 2025 guidance revisions.

Collectively, these actions streamline and high-grade our portfolio help us to meet or exceed our debt target and uniquely position us with significant inventory duration in the two most valuable oil plays in North America, the Permian and the Montney.

Before we get into the transaction details, Corey will give you a quick overview of our third quarter results.

Thanks, Brendan. We delivered another strong quarter, once again meeting or beating all of our guidance targets, setting us up for a strong finish to the year. We generated cash flow per share of $3.47 and free cash flow of $351 million, both beating consensus estimates. We also returned approximately $235 million to our owners through share buybacks and our base dividend and reduced net debt by $126 million.

Production during the quarter was at the high end of our guidance ranges across all products. The beat was largely driven by the Montney as we continue to see strong efficiency gains from our recently acquired [ CAR and Wapiti ] assets. We came in below the midpoint on capital, and we also match or beat our guidance on all per unit cost items.

Our third quarter results demonstrate the ongoing resiliency of our business and our constant pursuit of capital efficiency. Despite the more than $10 per barrel drop we've seen in WTI oil prices since the first quarter of 2024, our cash flow per share has remained relatively consistent. We've updated our full year guidance to incorporate our year-to-date results and improved Q4 outlook by increasing our production targets for all products while maintaining our capital guide.

As a reminder, we lowered full year capital by $50 million last quarter to reflect our efficiency savings. For full year 2025, we now expect to deliver 10,000 BOE per day more production or $50 million less capital compared to our original plan.

In the fourth quarter, we expect our total volumes to average approximately 620,000 BOEs per day including about 206,000 barrels per day of oil and condensate and capital is expected to come in at about $465 million. We've also adjusted our guidance to include an anticipated reduction in our 2025 cash tax bill of about $75 million or about 50% less than we originally expected. This reflects the impact of an internal restructuring and evolving U.S. tax guidelines. We expect these reductions to be durable for the next several years. In short, the team turned out another great quarter, and our 2025 outlook has improved once again. I'll now turn the call back to Brendan.

We've been operating in the Montney for more than 20 years and in the Permian for over a decade. Bolstering our position in these two dates where we have a competitive agent means we can continue to deliver durable returns for many years to come. Today's transaction marks a culmination in our strategy in our strategic positioning of the company to create a focused, high-return deep inventory portfolio.

In total, since 2023, we've increased our Permian and drilling inventory by more than 3,200 locations at an average of $1.4 million per net [ 100 locations ]. This inventory like expansion has been unmatched by our peers and leaves us with one of the most valuable inventory positions in the industry. This portfolio, combined with our execution capability, uniquely positions our company to generate superior returns for a long time to come.

The NuVista acquisition checks all the boxes. It's accretive across all key financial metrics. The combination enhances our returns, add scale and extends our future inventory runway in a core area. It boosts the quality of our oil inventory and enables us to maintain a strong balance sheet.

We identified NuVista through an in-depth technical and commercial analysis of the Montney to identify the highest value undeveloped resource. That analysis highlighted the NuVista assets along with the Paramount assets we acquired earlier this year as being the most attractive and most complementary to our existing Montney position. NuVista sits in the core of the oil-rich Alberta Montney. It's directly adjacent to our existing operations in [ CAR, Wapiti ] and Pipestone. It is largely undeveloped and it comes with significant processing capacity for future oil and condensate growth optionality, along with the downstream market access portfolio, that provides valuable natural gas price diversification outside the AECO market.

This is one of the highest quality undeveloped acreage positions in North America and the overlap with our existing land makes us the natural owner. While the assets are among the very best in the Montney on a stand-alone basis, the combination with our acreage is an ideal setup to unlock significant value.

This transaction will add approximately 930 net 10,000-foot equivalent well locations across 140,000 net acres. Extending our Montney oil inventory to the higher end of our existing 15- to 20-year range. But this transaction does not just add inventory, it makes our overall Montney position better. Folding in NuVista will result in a 10% uplift to our average Montney oil type curve.

Importantly, we are acquiring this high-quality inventory at a reasonable cost. For about $1.3 million per well location, which is very attractive compared to recent transaction metrics in the Lower 48. The acquisition provides strong financial accretion and will result in immediate and long-term expansion in our per share metrics like cash flow, free cash flow as well as increased ROCE. It will enhance our scale in the basin increasing our 2026 expected Montney oil and condensate volumes to about 85,000 barrels per day. The acquisition is expected to be leverage-neutral at close, and we will retain ample liquidity and a strong balance sheet. With this transaction, we are creating a stronger business that will be even better positioned for near- and long-term value creation.

Let's dive in with some more details about the NuVista assets. The team at NuVista has done a great job building a contiguous position in the core of the Montney oil window, and we're excited to combine it with our existing assets. The acreage pairs incredibly well with their existing land base. As you can see on the map, it could not be a better fit. We acquired acreage is about 70% undeveloped with about 400 horizontal wells producing today.

In 2026, we estimate the NuVista assets will deliver average volumes of about 100,000 BOEs per day, including about 25,000 barrels of oil and condensate and 400 million cubic feet a day of natural gas. The transaction also comes with significant AECO price mitigation and diversified market access, which Greg will describe in more detail later in the presentation.

I should point out that as a Canadian company, NuVista reports its volumes on a net before royalties basis and uses Canadian dollars as its reporting currency. So the numbers we quote will look different than their reported numbers. I'll now turn over the call to Greg to walk through more of the details.

Thanks, Brendan. This transaction adds depth and duration to our premium inventory and further expands our leading Montney scale. The 620 premium locations assume spacing of 10 to 14 wells per section, while the 310 upside locations assume up to 16 wells per section in the most prolific areas. Plus additional infill opportunities. This is consistent with the development approach taken on our legacy assets, including the Paramount assets acquired earlier this year.

Next year, we expect our pro forma 2026 total Montney production to average about 400,000 BOE per day, including 85,000 barrels per day of oil and condensate and 1.75 Bcf per day of natural gas. We anticipate running an average of six rigs and one to two frac crews. We'll have further details to share on our 2026 capital program when we issue our full year guidance in February.

We are confident in our ability to unlock significant value from the NuVista assets using our proven development approach to generate superior asset level returns and unmatched capital efficiency. We expect to capture about $100 million in durable annualized free cash flow synergies. About half of the synergies are from lower capital costs. We expect to achieve a savings of $1 million per well consistent with our current Montney well costs from streamlined facility design and faster cycle times.

The balance of the synergies come from other non-well capital savings, lower production costs driven by enhanced scale connecting the wells to our Grand Prairie operations control center, where we use automation and in-house AI tools to optimize production and reduce downtime as well as lower overhead. We are highly confident in our ability to realize these synergies given our strong track record of asset integration, which we demonstrated most recently by achieving our synergy target within the first 6 months of owning the Paramount assets.

We also see the potential for significant future savings from things like the ability to optimize our development plans, giving more available processing capacity. The ability to extend the lateral length of our wells currently are constrained by lease lines. and the opportunity to further optimize our base production, thanks to more integrated infrastructure. The enhanced value of our business is both structural and durable and will support increased direct returns to shareholders and higher return on capital employed.

Our confidence in the quality of the new assets is evident in the strong well results from NuVista on this acreage. When we overlay New Vista's average well productivity from 2023 and 2024, the acquired assets have delivered impressive cumulative oil rates. Integrating these assets into our Montney development plan results in a 10% oil and condensate productivity improvement for our previous program type curve.

This is illustrated on Slide 13, where the dashed orange line shows our previous repeatable program and the thick orange line represents our new repeatable program with the addition of the new Vista assets. This is a powerful demonstration of the underlying rock quality we're acquiring. The returns in the Montney oil window are competitive with the best plays in North America. This is a result of the high well productivity the low drilling and completion costs, the favorable royalty structure and the fact that Canadian condensate generally receives very close to WTI pricing. The economics are not dependent on a higher NYMEX or AECO price. Even at very modest AECO prices, these wells would still compete for capital in our portfolio. Our analysis of the pro forma assets show that at the current strip pricing, we expect the NuVista assets to generate a 55% rate of return in 2026.

The transaction comes with about 400 million cubic feet per day of natural gas. NuVista's downstream firm transportation agreements and hedging arrangements will lower our exposure to AECO on a pro forma basis. Ovintiv's 2026 AECO exposure will go from about 30% of our Montney gas production free transaction down to about 25% pro forma. NuVista's approach to AECO price mitigation is very similar to ours. They have done a great job of building out a diversified portfolio of firm transportation contracts to markets across North America, for about 250 million cubic feet per day of their natural gas volumes. They've received strong realized pricing as a result. Year-to-date, as of the end of the second quarter, the pre-hedge gas price realization was approximately 180% of AECO.

In addition, they have [ JKM ] link contracts for 21 million cubic feet per day starting in 2027. They also have a strong financial hedging program with a current mark-to-market value of about $120 million. NuVista's significant processing capacity unlocks future growth optionality for us. They have secured 600 million cubic feet per day of long-term raw inlet processing capacity, which when combined with our existing Montney processing will provide optionality for Ovintiv to grow our oil and condensate volumes by more than 5% for the next 3 to 5 years with no major infrastructure spending requirements. We've had good success collaborating with midstream partners to improve uptime at the facilities we inherited through the Paramount transaction, and we are confident we can continue to add value with future processing optimization efforts across the play. I'll now turn the call back to Brendan.

Thanks, Greg. Our work to build inventory depth is not restricted to the Montney. Over the past several years, we've extended our Permian oil inventory runway to nearly 15 years. It's no secret that the price of inventory has gone up dramatically since 2023 when we acquired over 1,000 drilling locations in the Midland Basin for an average cost of about $2 million per well. We were ahead of the pack and as recent transactions in the play value the inventory as much as $7 million per well.

While many people think there are no opportunities left to add inventory and make a reasonable rate of return, our team has continued to focus on bolt-on blocking and tackling across our acreage position. Our Permian ground game has yielded impressive results, acquiring low-cost, high-quality inventory in the core of the play. Year-to-date, we've added 170 drilling locations, 90% of which are premium for an average cost of $1.5 million per well. These transactions do not include any producing wells. They are inventory accretive, and they're offsetting our existing acreage and compete for capital immediately.

We think there are more opportunities for reasonably priced bolt-ons in the play and we will continue to take a value-driven approach to evaluating future prospects. We are funding the NuVista acquisition with a balanced mix of cash and equity. The sources of cash include cash on hand borrowings under our credit facilities and proceeds from a term loan. We've chosen to pause our share buyback program for 2 quarters until around the time the transaction closes. This decision, coupled with our balanced financing mix should result in a leverage-neutral transaction at the time of closing.

During this time, we've also caused bolt-on spending, and our base dividend is unchanged. Debt reduction remains a key priority for us. and we remain committed to reaching our net debt target of $4 billion or about 1x leverage at mid-cycle prices. As such, we have chosen to accelerate our pace of debt reduction and further streamline our portfolio through an asset disposition. We remain committed to preserving our investment-grade credit profile, and we do not expect a negative impact to our investment-grade ratings because of the NuVista transaction. We plan to commence a sales process for our Anadarko assets that we expect to complete by the end of next year. The Anadarko is a highly valuable asset with a low decline rate, strong realized pricing and low LOE. It punches above its weight in free cash flow generation. In the third quarter, it produced roughly 100,000 BOEs per day, including 29,000 barrels a day of oil and condensate.

Following the divestiture, we expect to be well below our net debt target. Enabling us to allocate a greater portion of our free cash to shareholder returns. We continue to believe our equity is undervalued and share buybacks continue to screen as a superior return on investment compared to investing in growth. We will provide more details on what a refreshed shareholder return framework could look like as we get closer to the sale of the assets.

In summary, yesterday's announcement reflects years of work to build the portfolio that delivers on our durable return strategy, and we're excited to reach this milestone on behalf of our shareholders. I'd like to recognize the efforts of our team to get us here. The NuVista assets in our ground game additions strengthen and expand our position in the top 2 oil basins in North America. The NuVista transaction is strongly accretive to our financial metrics as well as our premium inventory debt. It significantly boosts free cash flow per share provides significant oil growth optionality valuable gas price diversification and maintains our investment-grade rated balance sheet.

Our track record of asset integration and operational excellence gives us confidence in our ability to deliver on the targets we've set out today. We have one of the most valuable premium inventory positions in our industry. We have worked diligently to focus and high grade our asset base while strengthening our balance sheet. We now have the achievement of our debt target firmly in sight, and with that, the inflection to deliver increased returns to our shareholders. Operator, we're now ready to open the line for Q&A.

[Operator Instructions] Your first question comes from Kalei Akamine with Bank of America.

Congratulations on the deal. I want to add on the growth outlook for the New Vista asset. So NuVista was prosecuting a linear growth strategy through a decade in, and that was really enabled by their investments in gas processing capacity. And the timing of that, it's pretty imminent. So my question is, how are you thinking about balancing or optimizing those plants versus your capital discipline approach to capital spend?

Yes. Kalei, thank you very much. Appreciate the comments and the question. Yes. So we're going to fold this in and run our combined business in the same capital disciplined way that you've seen us do over the last several years. And really what that has us thinking about is a couple of items. One, what's the macro, what's the demand for growth from large E&P companies? And I think today, it's fair and reasonable to say there is not a market demanding more barrels or BTUs be produced. And so that signal calls for a maintenance level investment. And then the other signal we look closely at is can we get better cash flow per share growth from buying our shares back or from adding activity in the field. And again, that signal is telling us it's a better option for our shareholders to buy the shares back to generate that cash flow per share growth.

So when we incorporate these NuVista assets, we're going to fold them into that same capital allocation strategy. And so we'll be slowing that rate of growth investment down and running the assets for free cash generation if the environment continues to be the same.

I appreciate that. For my follow-up question, I want to ask about the 900-plus locations that you're acquiring with NuVista. That includes 300 upside locations I want to understand the plan to derisk those upside locations and whether that process is kind of already on the way, considering that you're doing some similar work on the Paramount assets that you acquired earlier this year.

Yes, Kalei, great question. I'll probably get Greg to comment here, too, because you're exactly right. This acreage sits side-by-side with both our legacy Montney acreage but also the -- now, I guess, now legacy acreage from the Paramount acquisition. And so the ability to take the learnings on well density across into this new acreage has given us a lot of conviction. But Greg, you can kind of comment on some of the specifics on time line.

Yes. Thanks, Brendan, and thanks for the question, Kalei. You're spot on. If you look at the math, this acreage just really nicely fits in that hole between our Pipestone acreage and our Paramount acreage we acquired earlier this year. We'll take the same approach. In some areas, that's going to be two zones up to three zones to up to 16 wells per section. We're already well on our way at delineating the Pipestone acreage to see how much of that upside we can convert to base we'll take the exact same approach here on the NuVista acreage.

They've already done a pretty good job of that. We feel like there's some room to go. So it will just really fold right into the work we're already doing.

Your next question comes from Phillip Jungwirth with BMO Capital Markets.

On the year '26 time line for the Anadarko sale, is there anything you're looking to prove up ahead of the sales, such as maybe like 3-mile laterals or more optimized cube? Or do you think most of this work has been done? And then I just want to ask also if there's been any reverse inquiries received to date, recognizing you're starting to process early next year.

Yes. Thanks, Phil. Great questions. Lots of interest in the Anadarko asset. As you might imagine, there's been some precedent transactions in that basin. So our interpretation is there's a very strong buyer market in that basin for assets like ours and so I think on time line, nothing to prove up technically in the play. This is a really well understood, low decline basin with lots of certainty in it. And so I think the time line will just be about maximizing proceeds for our shareholders. So that's how we'll be thinking about the time line.

Okay. Great. And then just depending on the actual proceeds received from the sale, how much below $4 billion of net debt would you view as a floor? I think in the past, you've talked about some interest in going below that. Our model would put net debt at low 5s, call it, by year-end '26. So feel like you could be quite a bit below this $4 billion target. I'm just wondering how -- where would you view the floor as we think about go-forward capital returns?

Yes. Great question. Love the forward look there. I think the way we'll talk about that is we've got to get there and make those decisions with the facts of the moment and the macro at the time. But if you took today's lens and you looked at it, that would be a tremendous opportunity for boosting those shareholder returns as we've indicated.

Next question comes from Scott Gruber with Citigroup.

Curious about one over the long term, we can do the math on where that probably lands in '26. But curious kind of your ability to push that down over the next 2 to 3 years after you realize the cost savings underpinning the deal and optimizing activity without a coming lease line, just some thoughts on being able to squeeze many maintenance CapEx down even further and where you think that could land?

Yes. Thanks, Scott. Love how you're thinking about it. We highlighted a number of longer-term synergies. We've obviously pointed to the shorter term capital and cash cost synergies, but there are some longer-term synergies here as well putting these two asset bases together, boosts our type curve ability to drill longer laterals, things like that. But Greg might have a comment on how we'll think about continuing to add efficiencies in the play.

Yes, thanks for the question. We'll -- in the very short term, we'll work on getting the cost on these new assets down to our cost structure, which will be around $525 a foot. But then over time, in all of our plays, we usually are able to continue to see a 2% or 3% reduction year-over-year just due to efficiencies in our program. So we'll continue to drive that down, just organically. And then some of the really, I think, attractive opportunities of -- if you look at the map, I mean, this is just ripe for opportunities to link on laterals across lease lines, to share infrastructure. We've already identified some spots where it looks like some of their infrastructure will replace capital spend that we were planning on in the next year or 2. So we feel like we're going to be able to drive down our capital structure here significantly over time.

If you think about -- we're not ready to give guidance for next year, but we'll probably have about 1/3 of our activity on this new acreage, 1/3 on the acreage we acquired last year and 1/3 on our legacy. So we'll have opportunities to learn and get better in all three places. So we feel like over time, we're going to continue to just drive down what's already an industry-leading capital efficiency up there.

I appreciate that color. And then you -- well proactive. A quick follow-up on the well productivity delta. It's a decent step above yours and looking for a nice 10% improvement on a blended basis, is the delta there all rock quality? Are they undertaking a different style of completion? What do you attribute that Delta 2? And if it is rock quality, do you think about pivoting more activity in that direction over time?

Yes, Scott, great question. Yes, it's all oil mix. So this is really a fluid window. So where the NuVista acreage sits relative to the basket of Ovintiv acreage, it runs just a little more oily. So net-net, our oil type curve goes up on mix. So that's the driver there.

Your next question comes from Betty Jiang with Barclays.

Good morning. Congrats on the acquisition. I want to ask about the processing capacity and on the midstream front, specifically for the Montney. With its [indiscernible] scale, are there opportunity to optimize how you utilize the different plants the flows, utilization of different plants and the opportunity to potentially negotiate better contract on the midstream front.

Absolutely on the midstream side, it's one of the deal synergies that's sort of baked into some of the cash cost piece, but also the capital and then in the longer-term unquantified synergy bucket here, too. So there's lots to talk about here. If we focus on the midstream side, Greg just alluded to this earlier, there are several places where we can avoid some capital expenditure that we would have had for minor infrastructure projects that now could come out because these assets come with spare capacity. So that's kind of immediate.

One of the big wins we've had on the Paramount integration is around run time. And so we expect an integrated asset here is going to also be able to boost run time through these midstream and processing facilities. And then the final piece is around the ability to grow into these assets over time when the macro calls for that in the future. So a lot of good wins to capture on the midstream infrastructure side here.

That's great. And then a follow-up on the gas marketing side, just given the larger position, do you see adding scale enabling more opportunities to market gas, whether on the global LNG front or other ways to mitigate your exposure to AECO.

Yes. Absolutely, Betty. So our strategy has been to minimize our exposure to AECO and we've been steadily chipping away at that over the last number of years, and in particular, since we acquired the AECO exposed gas from Paramount. And we're going to continue to do that. One of the deal features we love here as it does reduce our AECO exposure in the next several years from about 25% -- sorry, from about 30% down to 25%. So there's a built-in step change from combining these assets together. And we will continue to look for other downstream markets to diversify our AECO away from. And I know our midstream and marketing team is hard at work on that today.

Your next question comes from Lloyd Byrne with Jefferies.

Congratulations on the transaction and the -- frankly, the entire portfolio transformation over the last couple of years has been really good. Can you just start with -- maybe the question that started off on potential growth going forward. we kind of think you can grow these assets on a liquids basis, if you want. And is there any infrastructure processing constraints that you have that we block that?

Yes. Thanks, Lloyd for the comment and great question. So if you think about what this transaction does, we had already built a real growth option in the Montney oil with the addition of the Paramount acreage because that came with some spare processing and midstream capacity as well. This one boosts that up. So we had previously been talking about kind of that low to mid-single-digit growth potential for oil and condensate compounded over several years. This now boosts us up to be able to do over 5% growth for up to 5 years.

And so if you think about what that could mean, it could take our 85,000 barrels a day in the play up well north of 100,000 barrels a day over that period if we chose to make those investments.

So again, I'll caution that is not our capital allocation plan today in this macro environment. But in the event of a stronger macro environment, this -- both the inventory depth and the processing facilities are there to be able to facilitate that growth without major infrastructure investment.

And you didn't ask it, but I'll pile on a little bit here. Obviously, the addition of our ground game locations in the Permian also give us a lot of confidence in that growth option as well. And that is also a place where there is ample processing capacity available should we choose to exercise that. So really, we've got that growth option unlocked across the future portfolio here.

That's great. beat my second question. I just wanted to ask you about the ground game in the Permian. I just -- what is it that allows you to keep adding those locations at an attractive price? And can you -- do you think you can continue that going forward?

Yes. Thanks, Lloyd. Appreciate you back there. The -- this is a great example of how the ingenuity and approach that our team is taking is exposing our shareholders to a unique value-creation options. So really where our comparative advantage comes into play here is if you're a large mineral rights holder in the Permian, the operator of choice for you is open to we're going to get you the best royalty stream off of these assets because of our cube development approach and because of our reoccupation strategy and how we conduct our operations in the basin. So that's allowing us to access really high-quality resource at a very attractive entry price for our shareholders, and we look forward to seeing what that can yield in future years as well.

Your next question comes from Doug Leggate with Wolf Research.

So obviously, you've set the table for the Anadarko sale. I wonder we're coming into potentially what some would make a softer oil outlook. Are there any conditions where if you don't get what you hope to achieve in terms of valuation that you would hang on to that asset longer? Or is it a sale regardless of the -- I mean how are you thinking about framing the conditions of sale.

Yes. It's the right question, Doug. I think, look, the one thing I'll point out, first of all, is the Anadarko, while it makes a fair amount of oil, it's about 1/3 oil, 1/3 NGLs and a third gas, so it does have good commodity exposure across the three products here. So it's not exposed to one exclusively, which is helpful in really any environment. And then this is a really high-quality asset. It's going to attract, I think, a lot of attention. And then we've given ourselves a reasonable running time here to execute. And so we'll be working through that time period to maximize the proceeds to our shareholders, but certainly cognizant of making sure we do that.

And then I wonder if I could be predictable and ask you about the capital return strategy. you're taking a pause on the buyback. We certainly can't understand why your free cash flow yield is as high as it is. But at the same time, we look at the capital structure and I think share buybacks are glacial. They're not working in terms of forcing market recognition of value, and you've got this opportunity to pause and basically test perhaps what happens if you lower your net debt and transfer that value to equity. So I guess my question is, you seem to be messaging the $4 billion floor and then a reset potentially in the share buyback why not just take the debt down and reset your capital structure altogether?

Yes. I think, Doug, that's exactly what we'll be doing with the transaction. So I think we continue to be an agreement here about where we're trying to get the business to. And so we think the prudent approach we're taking here with the pause until close allows us to be leverage neutral with where we are predeal. And then the transaction on Anadarko would enable us to immediately step change below that debt target, so. And give us the flexibility from there. So yes, I think we're agreeing with you.

Your next question comes from Breda [indiscernible] with Goldman Sachs.

I was just wondering if you could speak a bit on the drivers of the $100 million in annual capital and cost synergies outlined with the NuVista acquisition. Are these similar changes to the changes made while incorporating the Montney acreage from the Paramount acquisition at the start of the year? Or are there different opportunities you would highlight there?

Yes. Great, I'll let Greg chime in on that.

Yes. Thanks for the question. First off, I just want to compliment you visit. They've done a really nice job with the assets to this point, which is why we were so interested in acquiring them. But our team has developed a really well-defined and refined integration playbook that we'll start -- think of it kind of in two lenses. There's the short term, that first day up to the first 6, 9 months. And then longer term, how we approach things. But just immediately after close, we'll be connecting their rigs up to our drive center where we'll use in-house algorithms and AI to further refine our drilling efficiencies as well as our cost base in learnings on things we've learned here in the U.S. We think that's going to drive several days out of drill times.

On the completion side, we're going to use -- utilize our real-time frac optimization center, which will refine pumping schedules, shorten cycle times. Our use of local sand there in the basin which should also generate some really good cost savings shortly after close. And then on the facility side, we see some significant opportunities to reduce cost of both the new facilities we're going to build, but then longer term, as we showed on Slide 15, there, our acreage position in midstream are really well aligned where they're located close to each other. So we should be able to reduce facilities costs going forward and optimize that.

So on the capital side, that will make up about half of the efficiencies we're going to see. And we think that's going to happen pretty quick. I mean we're going to measure that in months, not quarters or years. But then just importantly, on the production side, we're going to reduce costs there and get more efficient. We'll do just what we did on the last transaction. We're going to connect the wells to our operations control center in Grand Prairie very quickly and inexpensively. And from there, we'll be able to optimize production using our in-house AI tools and algorithms to optimize production on all the wells with set points on artificial lift, those types of things. But also what we found to be very effective is the automation that we put in place. So we can not only shut in wells remotely, but also bring them back online in minutes.

And so while we've really improved the midstream reliability, and we think we'll be able to work with the new midstream providers here to help them as well. When inevitably you do have a downtime or a turnaround, we can bring our wells back online faster than anybody else in the industry up there. And what that does is just really increases our uptime. So you'll see a production benefit there as well as a cost reduction. And then when you look longer term, as I spoke about earlier, we're going to be looking to go to longer laterals. We've got some shared acreage that actually had a shared working interest between Paramount and NuVista historically.

We'll be able to make those 100% working interest wells, extend lateral lengths, develop that very efficiently. We'll be able to share up and optimize infrastructure spend. And that will also help base production as well as new wells. So just lots of different ways we're going to be able to achieve this over the coming months and even longer. So really excited teams looking forward to get to work on optimizing this asset.

Great. And then just for my second question, I was wondering if you could speak a little bit more about the decision to fund the acquisition through a combination of both equity and cash. Can you speak a little bit about why 50-50 split is the optimal split in your view?

Yes. Thanks, Greta. I think the right place to start here is with getting the total consideration right. And so that obviously was the starting point for us. And then the next is to find the right balance on the financing mix. We were very disciplined with how much equity we used in the deal. It's our view that our equity continues to be undervalued. So we wanted to be disciplined with how we use those shares. And then we also wanted to make sure we held leverage neutral, like we've described at close here. And so really, those are kind of the governing features with how we thought about mix, and we think the outcome accretion and across the board, uplifts to the business makes sense with that mix.

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

I always appreciate your view on AECO and Canadian gas prices. You made the point with this transaction that it lowers your AECO exposure and you're acquiring some really nice hedges over the next several years. But I wonder if you could update us on your long-term outlook for AECO and the Canadian gas markets and maybe what key projects would make you a little bit more constructive?

Yes, Kevin. Obviously, we've been cautious on AECO as the start-up of LNG Canada is helpful and an important milestone for Western Canadian gas producers, but also recognize the basin continues to be highly productive with a lot of growth capacity. And so we've been kind of near-term cautious. I think I would describe it as we look out into 2026, a little more constructive as that LNG Canada ramps up, but still cautious because it's not the end all and be haul. But if you look forward to the LNG projects that are queuing up towards the end of the decade and into the early part of the 2030s, we think there's a real optimism around Western Canadian pricing. And what the additional egress could mean to the basin. And so built into our Montney business is the gas option, and we are long term excited about the value embedded in that gas option.

And just for clarification on the Permian inventory additions. Was the $250 million in spending in October. Was that just from one transaction. Or was that several small deals that are -- that happen to be closing at the same time?

Yes. We bucketed together several deals into that to achieve that. So true ground game fashion there.

Your next question comes from David Deckelbaum with TD Cowen.

Good morning, everyone. Thanks for taking my questions today. I wanted to just follow up on some of the allocation conversations and some of the synergies with the new Visa transaction. You guys highlighted obviously the superior well productivity. And I think you talked about kind of splitting your activity evenly between Paramount and NuVista and Ovintiv acreage up in the Montney. I guess is there a future outlook that you would be moving tit to more aggressively accelerate the development. It sounds like you're not constrained from an infrastructure side. On the new Vista acreage so that would sort of increase your free cash per share metrics?

Yes. Look, we are going to allocate capital across the Montney to maximize free cash flow, but also bear in mind our reoccupation strategy, which is really a reservoir management strategy to come back and drill cubes beside tubes within 18 to 24 months. And so those will be the two things that largely govern along with processing capacity, but those would be the things that govern our capital allocation across the assets. But like Greg said, it might shift around a little bit, but I think it's pretty stable in that 1/3, 1/3, 1/3 across the three buckets of Montney acreage.

I appreciate that. And I know it's a bit early, but I share your view on the valuation for the Anadarko Basin seems like it should be approximately what you paid for NuVista on [ PDP ] alone. So I'm kind of curious, just from a tax perspective, how you think about any tax slips from transacting there or if you have some offsetting mechanisms?

Yes. I'll let Corey cover that.

So just on that front, we've got some existing bases on the asset and then obviously, depending on how high the price is, we should be able to cover it with other tax attributes. So we don't forecast much if any tax leakage on the sale.

Next question comes from Chris Baker with Evercore ISI. .

Thanks, just a quick one. It sounds like this asset has been identified quite some time ago. I'm just curious in terms of the ultimate timing that we're seeing here. Was that at all influenced by the share sale, obviously, you mentioned in the release or just anything around the timing piece given the Anadarko assets, that would be helpful.

Yes, Chris. Look, you're quite right. So we had identified this as 1 of the 3 assets that made a lot of sense for us as we went through this portfolio transition. And so pleased to be able to get to this point here today. I think the way to think about it is the disclosure from NuVista highlights, they began a competitive process for the asset back in August. And we acquired the shares right at the start of October. So that gives you some sense of the sequencing here.

I'm just going to say just clarify, you've been one of the...

The Northern Midland Basin, the Paramount and then NuVista with the three, yes. Yes. Good point. .

Got it. That's great. And apologies if this was covered earlier, but any sense on what run rate EBITDA looks like for the Mid-Con asset this year?

I don't have that number to hand here, Chris, yes. Sorry, I've got -- there's a lot of numbers in front of me right now, but I don't have that one.

Your next question comes from Geoff Jay with Daniel Energy Partners.

I just had a couple if I could. First is the soft guide for 2026 pro forma. Is that inclusive of the Anadarko production or exclusive?

Yes. Jeff, yes, it's inclusive of the Anadarko production. So we'll update that once we've got clarity on the divestiture timing.

All right. Great. And then my second is on the -- going back in, I guess, maybe beating a dead horse on Slide 12. But in looking at the future synergies piece, I noticed your AI and production optimization are kind of in two buckets, near term and long term and I am wondering what the long-term, I guess, AI automation piece is and what makes it long term?

Yes. I mean we're just at the very front end of applying these technologies into our business. And as you saw, Geoff, when you joined us in the Montney this past summer, we're active in sort of three main areas. We're active in the production operations place. So it's helping us on the uptime and on the artificial lift optimization. It's helping us on the drilling times and costs, and then it's helping us on the completions, both the cost and the productivity of the wells. So -- but we're really early days in trying to figure out what this technology can do for us. And so hard to point to where it's going to go over time, but put us in the optimistic camp here of seeing the potential for this to really transform our business.

At this time, we have completed the question-and-answer session. And I'd like to turn the call back over to Mr. Verhaest. Please go ahead.

Thanks, Pam, 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 ask that you please disconnect your lines. Have a great day.