OVV

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2026 1st quarter results conference call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing star one. For members of the media attending in a listen-only mode today, you may quote statements made by any of the Ovintiv representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Ovintiv.

I would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.

Thanks, Joanna. Welcome everyone to our 1st quarter 2026 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'll now turn the call over to our President and CEO, Brendan McCracken.

Thanks, Jason. Good morning, everybody, and thank you for joining us. We 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 ROIC and substantially reducing debt.

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, 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, 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 de-risked 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 pro-cyclical buybacks. We also believe it makes sense to take the opportunity to further accelerate net debt reduction. If oil prices continue to stay elevated, we would expect to be in the 50%-75% range.

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. As of April 30th, our net debt was less than $3.3 billion or less than 0.8 times 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 right-sized. 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 non-cash 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 months 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. The impact on the fundamental supply and demand dynamics remain unclear. Our portfolio now has significant duration and capability to grow production. We believe it is still prudent to maintain our stay-flat program with level-loaded activity in both the Permian and Montney and let 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 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 curves. We hit our 85,000 barrel per day target in the first month after closing the acquisition, and we've 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 load 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. While gross volumes are unchanged, higher royalty rates mean our reported net volumes are reduced. On slide 10, we 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%-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 15/16 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 is 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 one of taking ownership of the NuVista assets, and they haven't looked back. We split our first pad on the NuVista acreage, the Wapiti 6-2, 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 well site 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 cost.

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 12-15 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 in 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. 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 Enverus, 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. A 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've said this for a while now, 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, 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're now ready to open the line for questions.

Thank you. Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing star one. We will now begin the question-and-answer session and go to the first caller. First question comes from Greg Pardy, RBC Capital Markets. Please go ahead.

Yeah, thanks. Good morning. Thanks for the rundown, guys. 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, you know, your optimal financial leverage, or is this just being thoughtful around, you know, windfall cash flows versus purchasing stock right now?

Yeah, Greg, thanks for the question. Yeah, 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. This is really more a choice of allocating capital and just letting cash build on the balance sheet. Over time, you know, obviously, we'll look at opportunities to take out further debt, but, you know, we don't have that much cash at this point that we give an April month-end number. It's about $400 million of cash on hand right now.

Okay, thanks for that. Brendan, for the last, you know, few years, you've just emphasized, look, the market's not looking for additional barrels to come on the market. Beyond the oil price escalation, which, you know, 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. My question for you is, as you look forward, is there now a more compelling case to grow condensate in Canada, or you know, is what you're looking at just more temporary from an oil price and strategic perspective?

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

That's already happened, you know, 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 WTI. Then I think as the dynamics unfold and more oil sands growth comes, we're just gonna see more and more constructive condensate fundamentals. That's the specific condensate part. I'll just touch briefly on the overall macro and how we're seeing that unfold. You know, 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 gonna see here. You know, clearly we've got some pretty constructive front month dynamics.

You know, this isn't gonna surprise anybody, but we're watching closely to understand, you know, when is the strait gonna 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. 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 gonna unfold? Of course, in the major consumer markets, you know, principally China, how are their demand picture gonna unfold over time? Just a lot of different factors that we're watching unfold, but certainly a more constructive macro than we expected coming into the year.

What we're looking for now is duration in that signal.

Understood. Thanks to you both.

Yeah, thanks, Greg.

Thank you. The next question comes from Doug Leggate with Wolfe Research. Please go ahead.

Good morning, everyone. Thanks for having me on. 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 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? My follow-up, if you don't mind, Brendan, is for you, and obviously thrilled to see the, you know, the shift towards putting cash on the balance sheet. I think you know our view on that. 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? Thanks.

Doug, thanks for your question on productivity. Generally, we just continue 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 five or six years.

We're seeing that 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, you know, diagnostic program, we've been doing a lot of work with geochemistry, where we actually fingerprint the oil. 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. That tells us that the wells being treated with surfactants are not only performing better, but the oil comes back slightly different. That would point us to, yes, this is, this is different oil. This is additional oil and not just acceleration.

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.

Thanks, Greg.

Doug, this is Brendan. I can jump in on your question around mid-cycle pricing and the cash flows. 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. We've kind of had that as our mid-cycle price for quite a number of years. 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. If we look at that $55 WTI, that implies about a $4 billion cash flow number for the business.

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.

That's really helpful. Thanks so much, guys.

Yeah, thanks, Doug.

Thank you. The next question comes from Arun Jayaram with J.P. Morgan. Please go ahead.

Hey, Brendan. How are you?

Hey, Arun. Yeah, great. Good morning.

Yeah, good morning to you and the team. Brendan, you and the team have spent a lot of times making moves on the portfolio with some good trades to kinda, really clean up and, you know, 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's going to be, and the fact that you are kinda long inventory at this point.

Yeah, appreciate it, Arun. Great question. You know, really we think about the business now into a period of stability where we can sustain that inventory depth that we've created. 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. We're very excited that we've reached this kind of milestone with the portfolio, and today our focus is gonna be on driving incremental profitability. We think that stability has got real value for our investors and, you know, pleased to have put that behind us, having to build this premium inventory position. 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.

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. Sitting here, you know, 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. Then the Barnett position in the Permian effectively replaces 1 year of Permian consumption at least. So we're excited to, you know, already be playing with a full deck for 2026.

Thanks, Brendan. Maybe a follow-up and maybe a housekeeping question for Corey. On slide 16, you highlight your guidance items in the deck, including your updated views on kinda current taxes in a higher commodity price environment. Corey, you still are a very minimal U.S. cash taxpayer in 2026. If we assume kinda strip pricing today, any thoughts on how cash taxes could trend in the U.S. in calendar 2027?

Yeah, Arun, thanks. We all love getting tax questions on the conference call, so appreciate that. For the U.S., like if you took, if you took this year and replicated it again next, we'd expect a similar level of cash tax, so pretty minimal. Then into 2028, we become more of a full cash taxpayer on the U.S. side.

Got it. Thanks a lot, Corey.

Yeah. Thanks, Arun.

Thank you. Next question comes from Lloyd Byrne with Jefferies. Please go ahead.

Hey, good morning, guys. Thanks for having me on. 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?

Yeah. Yeah. No, for sure. You know, we put stacked innovation as one of those critical strategic steps that an E&P company needs to be able to hit home in order to deliver this differentiated value creation. 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. The companies that can demonstrate that capability are gonna demonstrate outsized returns and that should imply a lower cost of capital and a higher valuation. That's the build up for why we think it's important. You know, really what it 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 wanna look at returns or capital efficiency because of the method. 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. 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.

You know, we take an, I would call it an ambitious yet humble approach here. 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. We're also very humble because we choose to learn from what's happening around us. 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." We've been really aggressive about doing that.

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 built, they all point to Ovintiv running at the forefront of the industry on an efficiency basis. 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 two lowest cost operators in the Midland. 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.

I guess, thank you for that. Is there one technology or change that you're still most excited about from here?

Well, in the rear view mirror, the technology that's yielded a lot and has gotten a lot of market attention has been the surfactants. You know, 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's coming from surfactants. That's the rear view mirror. I mentioned this innovation pipeline that our team continues to try and fill up. 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. You know, we've got a number of other things that we're excited about deploying and testing over time.

I don't know, Greg, if you wanna add anything to that?

Yeah. I think it's a combination of improving well results, but also improving costs. 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 wet sand in many cases. It's just a 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 five to ten years. Lots of things have added up. There's still things in the hopper. We're not done yet.

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. 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 operation 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. Yeah, the innovation pipeline's as full as it's ever been and excited about continuing to bring those into the field.

Great. Thank you.

Thanks, Lloyd.

Thank you. The next question comes from Neil Mehta with Goldman Sachs. Please go ahead.

Hey, Brendan team. I guess since 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. Just, you know, without commenting on the specifics of that transaction, just curious what you think that means for the way that you're thinking about the value of your Canada business.

Yeah, Neil, appreciate the question. Yeah, 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, you know, that the capital is starting to be allocated globally towards the Montney. Not a surprise there. You know, we weren't involved in that transaction in any way. We had already skated to where the puck was going there with the two larger transactions we'd done in the Montney Oil Window to build the premier position in the oil window of the Montney.

You know, 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. 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.

Yeah. That's very helpful. 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.

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

Yeah, really appreciate the question and the opportunity to kinda dive in a little more. You know, kinda starting with just the map up in the top right, what we were able to take advantage of by combining these two acreage positions, we could take what were gonna be, you know, fairly modest length laterals and extend them down into our acreage position. As we all know, longer laterals, you know, yield better cost per foot. 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. 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. That's basically our real-time drilling optimization center. 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. We were able to drill faster. We were able to, you know, 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. All of those add into savings.

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. 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. We budgeted that way. On this very first pad, we're delivering at or below the well costs that we were planning on. Just a great execution by the team, really strong integration effort to hit the ground running just days after the acquisition closed.

That's great, Greg. Thanks for walking us through it.

Thanks, Neil.

Thank you. The next question comes from Gabe Daoud with Truist. Please go ahead.

Thanks, operator. Morning, everyone. 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? 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, just curious how you think through that.

Yeah, maybe I'll start with the second question, Greg can pick up the surfactant one. You know, Gabe, I think the great news is the early wells of the 2026 program are really strong in both the Montney and the Permian, we're not changing how we're planning the business at this point. The type curve for 2026 still holds. Always really nice to play with a lead, the team's done a great job of that through the first quarter, we'll watch how that goes through the year.

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 gonna be able to outperform and create differentiated results because of the work that we've built into the system here. Great to see the positive signal, but we haven't changed the long-term type curve plan for the Permian. Over to Greg on the surfactant.

Yeah. As far as our, you know, application of surfactants, we've really advanced our approach here over the last several years. If you were to go back in time, you know, initially, we were only pumping on a small number of wells. Our costs were something we were working to bring down. We've worked to really, you know, hone in on the right formulas for the right zones. I've gotten our costs down to $100,000 a well. Just for kind of walk you through the last few years, in 2024 it would've been about half of our wells got a surfactant treatment. In 2025 or last year, it was about 75% of our wells. This year it'll be almost all of our wells will be treated with surfactant.

You know, we're still, you know, toying around with a few zones. The Barnett, for example, not exactly sure what we would pump in that yet when we do that later this year. Almost all of our wells will get surfactant treatment, and we're doing it at a very low cost. As we talked before, seeing, you know, very, you know, solid uplift there. It'll be essentially all the program.

Got it. Okay. That's helpful. Thanks, Greg, and thanks, Brendan, on the other question. I guess just as my follow-up, your D&C per foot pretty attractive in both plays, and I know historically you would also highlight what the pacesetter is in both plays. 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. Curious what those pacesetter wells maybe look like on a D&C per foot basis, and then maybe reasonable expectation around when the pacesetter becomes the play average. Thanks, guys.

I'll turn it over to Greg, that's a good example of this innovation pipeline in action. You know, we love the pacesetters on the cost side because they tell us what's possible, then we go and chase that to make what's possible the average outcome. Over to Greg on what we're seeing there in terms of, you know, days per fee per day on the frack and drilling side, giving us some confidence there's still room to move on the well cost side.

Yeah. That's. 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, you know, faster than we ever have before. We're continuing to, you know, drill. You know, 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, you know, the last few quarters have been some of our fastest quarters. We are working, you know, to offset. There's a little bit of inflation in the system right now with diesel cost, being, you know, mainly passed through diesel costs.

I would say that we're continuing to, you know, trim half days and days off the drilling side. We're continuing to trim days off of the completion side. Today that's got us, you know, comfortably saying we're still below $600 a foot in the Permian and $500 a foot in the Montney. If we continue to have those faster cycle times, as we see, you know, the inflation, we think, ease a little over time, then that'll start translating in lower well costs. Right now, we feel very comfortable with the guide that we have out there today.

Understood. Thanks, Greg. Thanks, everyone.

Thanks, Gabe.

Thank you. The next question comes from Phillip Jungwirth with BMO Capital Markets. Please go ahead.

Thanks. Good morning. 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?

Yeah, Phillip, 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 you know, we thought long and hard about here, we would likely do it in both places. You know, the return proposition is the same in both and we have the capability from, as you said, from an inventory position in both. You know, we do think that is a very real option. We're saying today we're gonna 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.

You know, in the meantime, we're just gonna continue to lean in on performance to generate upside barrels in this price environment and, you know, watch how the macro unfolds.

You know, 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 a 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 'cause being in the bench can help. There's obviously fundamental elements of the story here with having a leading Montney position and ARC going away.

Yeah. Phillip, I think the combination of those fundamental improvements to the business, which we've spent enough time probably harping on today already, I won't reiterate again. The combination of those with that potential index inclusion would be quite constructive. You know, 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. I think the more important part is the fundamental appetite to own the shares is strong today in both Wall Street and Bay Street. We're seeing that in investor sentiment and interest.

Great. Thanks, guys.

Yeah. Thank you, Phillip.

Thank you. The next question comes from Kevin McCurdy with Pickering Energy Partners. Please go ahead.

Hey, good morning, apologies for staying on the subject of growth and shareholder returns. 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 there any update to how you calculate, you know, when you're deciding between those two uses of cash? Are you using the strip? Are you using mid-cycle prices? Kinda how do you calculate that?

Yeah, 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. Really, the fundamental intention we wanted to create is cash flow per share growth and the most efficient cash flow per share growth. What I'd say, and we had said for quite a number of years, is that calculation kept telling us buybacks were more efficient. Today that's moved much more into a balanced position. 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.

It opens that door a little more than it was the last several years. We like that. It creates a real option for cash flow per share growth, value creation for us.

Appreciate that. Maybe as my follow-up, I'll shift gears to OpEx. Upstream T&P was much lower than the guide in one Q. You chose to keep your two Q to four Q guide kinda 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?

Yeah, for sure. I'll take that one, Kevin. I guess first thing I would say is Q1 really is just a bit noisy on T&P. A couple of the puts and takes there. You know, it included our Anadarko volumes, which has a lower T&P rate. It includes some but not all of the NuVista. You know, we didn't have NuVista for the whole quarter, which is gonna be at the higher Canadian T&P rate, which is similar to our other Canadian assets. We also had some one-time adjustments in the quarter that were in our favor. 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. Go forward, our T&P is right in line with what we've expected.

If you kinda 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. Going forward, you'll see LOE come down or OpEx come down. T&P will be up slightly. All of this is very much in line with what we've expected all along.

Appreciate it, Greg.

Thanks, Kevin.

Thank you. Next question comes from Neal Dingmann with William Blair. Please go ahead.

Hi. Morning, guys. Thanks for the time. Maybe probably for Greg. Greg, my question is on the Permian plan this year. Specifically, I believe y'all have targeted around 125 to 135 wells. Will most of this continue to target Wolfcamp Spraberry, or are you targeting some deeper zones as well, like the Barnett?

Thanks for the question, Neil. Pretty straightforward program. We've got one Barnett well in the program. The rest of the zones we'll be targeting will be the normal stack going from Spraberry, Dean, you know, Jo Mill, all the way down through the Wolfcamp. No real exposure to Barnett other than that one test we're doing this year. 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. 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, we'll get costs down. This is a great opportunity. It's like Brendan was alluding to earlier, learning from peers. This is a great place where we can learn a lot, without spending dollars. We'll be watching our peers, and learning from them on the best ways to drill these Barnett wells cheaper.

Yeah, that makes sense. Just secondly on marketing, for the guys, specifically in the Perm, are you seeing near-term power opportunities or anything you're considering there?

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

That's what I was looking for. Thanks, Greg.

Thank you. Our last question will come from Christopher Baker with Evercore. Please go ahead.

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

Hey, thanks, Chris. No problem.

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

Thanks, Joanna. Thank you, everyone, for joining us today. Our call is now complete.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.