Ovintiv (OVV) Q2 2026 earnings call transcript

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 our disclosure documents filed on EDGAR and CDR+. 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 one times. 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 EMPs in North America, and we are very excited to be operating from this position of strength.

Both our Permian and our Montany 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 right-sized, 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 one times, 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 Motney 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 Montany. 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 depth 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, and 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 are consistently one of the highest oil productivity, lowest cost operators in both the Permian and the Montany. We have over a decade of experience deploying our systematic cube development approach, which means we co-develop multiple stacked zones from a single pad. This creates value by maximizing both returns and resource recovery. We also have around five 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 but 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, profit 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, enhanced 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 DOEs 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 Maunee 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 ACO 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 0.6 times. This was 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 Low. 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 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 Maundy, and that higher oil prices agree to free cash flow versus investing and 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, 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 roll, 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 volumes 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 Inveris, 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 lift parameters, reduce downtime, and flatten well declines. This is technology that we imported from Ramonty, 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 Montany 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 A realized price for the Canadian condensate was about which was a premium to WTI Although we don 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 Montany condensate volumes to average 80 to 85 barrels per day Also of note was our Montany gas price realization in 187 of ACO Our diversified portfolio of both physical sales out of the basin and financial arrangements to price our gas away from ACO 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 Motney 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 Motney peers.

We recently established a pace setter of more than 7,000 feet of completed lateral length per day using Simulfrack, 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 sands of 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 of ECO and Waha hubs.

We have the least ECO exposure of our Motney 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 price more than half of our gas outside of Waha with exposure to GCX, Whistler, Matterhorn, and starting later this year, the Hugh Brunson pipeline.

The result is that despite producing gas in two 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. We're 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 Motney, brought our debt down below $3 billion, and are set to grow oil production per share by 4% with no increase to 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.

Yeah, hey, Neil. Yeah, thanks for the question. Appreciate the interest here. You know, 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, you know, 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, you know, where we very carefully engineer these fracks 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 others, 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 recipes. 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, well, 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 Montany 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, yeah, that's, I think, the answer to your question.

Yeah, 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 have 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 18th event. And in that comment process they have specifically called out Ovintiv as one of three 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 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 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 from the Canadian investor, and then as well at least a couple of Montany players that are going away through transactions, one of which was New Vista that we acquired, and then Arc is the other one with Shell. So definitely all a tailwind for us.

Thanks, Neil.

Yeah, Greg, I appreciate the question. It's a good one. So we are very early stages in the Montne. 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 Montne, we're just really getting started there. So the lab results are very encouraging. If you think about four or five years of cycle time in the Permian, we're going to be able to accelerate that in the Montnei. So I don't think it's imminent to have a conclusion on the efficacy in the Montnei, 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.

Yeah, I think you painted it out there, Greg. I think, you know, 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 a 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 or 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.

And like you said, lots of free cash flow to enable the combination of buybacks. And then, you know, 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, you know, these are going to be the modest size deals. We think we've got line of sight and both Permian and Imani 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.

Yeah, so we're early days and excited about that. I think we're early days in both places, to be honest. I think the stack just grows with time. But, you know, turn it over to Greg to provide some color on that.

Yeah, I appreciate the correct question. I think if you think about all of the stacks that you see there on slide eight, 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 Montany for, you know, gosh, a decade now. But things like Simulfrac, WetStand, you know, that's had different levels of application in each of the two 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 Motney. As we just reported, our first wet sand, full wet sand trial in the Motney 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. So we're different places with each of the technologies. I think the one I most excited about is the AI and the new digital tools we 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 you know different places in each of the assets on the stack but applying it across the board and there still room to go from here Thanks Greg And then just second My second question is really diving in on the GPNT Specifically, could you talk about potential future GPNT cost savings?

Yeah, great question, Neil. The T&P, if you look at how it's broken out by country, the majority of it is in Canada in our Motney operation. And so what we're excited about here is we're really just getting going with the three positions being combined together. That is our legacy position, the Paramount position, and then the Nuvista position. And 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 into 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 TMP.

So we do expect this to unfold over time. It's probably going to be a multi-year 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.

Yeah, great.

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

Yeah, so thanks for the question, Arun. And yes, first off, we are saying 125 as 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 our 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, you know, 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. I know that performance has persisted.

But more importantly, we've seen that really good performance across the portfolio. We're seeing, you know, strong results from our new wells in all of the areas that we have at 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, you know, through our operations control center there in Midland, you know, we've been able to improve run times from our ESPs.

We brought 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, you know, 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, you know, zero days with shallows declines, and have really helped the base. So, you know, it's going to be a combination of the new well performance, the base performance, all of that coming together, you know, gives us confidence. And that's what allowed us to say, you know, we're going to be at 125 run rate going forward.

Yeah, I'll take that one, Arun. You know, we've actually seen really strong results across the entire position. We've had really strong results in our legacy, Wells Up and Dawson. We've had some good pads in Pipestone. as well as areas like Carr and Wapiti that are newer to the portfolio. So we've seen really strong results that, you know, a result of those stacked innovations. We've been working on our stage architecture. We've been looking at prop and intensity.

All the things that we've done in the Permian, we're doing those same things up in the Motney 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 Carr. 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 in the Sextma. So we're very pleased with results across the portfolio in Canada and expect that to continue.

Yeah, 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 us do. 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, yeah, 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.

Yeah, 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, you know, 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 it here. So I think we're taking a prudent and balanced approach with the capital allocation.

Yeah, you bet, Doug. Part of that prudence is the value that we see in the shares today.

Yeah, I'll pass over to Greg here, Gabe. One thought just quickly to set that up, because there's been a couple 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 in the play for a decade plus here now. 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.

Yeah, great. Thanks, Brendan. Thanks, Gabe, for the question. You know, 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 in cord. The vertical, the cord 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 it also gives us a lot of trade currency. We can trade that core and well data with our peers to learn more about what they're learning here. And we're also participating in really small working interests 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.

I would envision us drilling this one well this year, next year, another well or two. We'll just see how our progress goes there. We'll be learning all along the way and making sure we optimize our position.

Yeah, 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 ACO. 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 ACO. So more of the same there. And, you know, 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.

Thanks, Brendan.

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

You know 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 DNC spend Yeah, let Greg take that one on.

Yes, so great question. In addition to using electric frack cleats and the Permian, we also have a natural gas fired frack fleet operating in Canada, so we've 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 the 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 Motney, that eliminates truck miles.

That's one of our biggest pass-through costs is when transportation has to pass through the diesel costs. 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 efficiency. 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.

Yeah, great question, Chris. I think the, you know, exciting news today is the growth with no capital or activity. So that's kind of the first port of call as we start to think about 27. But, you know, we are also continuing to think about when might be the right time to invest for growth. Premature yet to say for 27, obviously, we're 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 and 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.

Yeah, 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, you know, we'll get to that in time as we work our way through the rest of this year and into next. But for now, the guidance makes good sense. I think boosting it up to the 125 is a real value accretion for our shareholders, and we're proud to be able to do it.

Yeah, John, thanks for the question. I'll pass it over to Greg. But historically, our approach has been to think about those pace setters as our target to convert to average. So the idea here is for the team to, you know, 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 pace setter, we've been able to convert that into our average performance down the road. But Greg, you can dig in a little deeper there.

Yeah, for sure. Starting with the Simulfrac, really the only limitation there is pad setup and logistics. And so I would say almost all of our operations in the Montany set us up well for Simulfrac, 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 two, you're going to see more domestic sand options. And then as they're putting in those sand vines, 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'll take, you know, this year we're at 50% domestic sand with a portion of that being wet.

You know, next year I would anticipate that growing, but we're still probably a couple years away from getting to a fully implemented program like we have in the Permian.

Yeah, I think the opportunity still looks fairly sizable. If you think about up in the Montney, when we did the two acquisitions, Paramount and New Vista, 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, you know, it's never going to be completely rateable. 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.

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

Yeah, 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. When you take those two into account, 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, you know, it's really just a combination of being in the market regularly and then also adjusting daily if there's something going on.

Yeah, hey Phil, great questions. The $100,000 per well has been part of this stacking process over the last several years, and just to give you the under the hood, when we started, the treatment costs were in that half a million dollars 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 were 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 be very careful about the chemistries that you choose to deploy at scale in the field. So when we started half a million a well, got some surfactants that were 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 half a 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, and a well-established protocol to do that. But on the base side of things, on the workover treatments, we've got 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. 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.

You know, so, you know, we've chosen to keep that one privileged to ourselves for now.

Yeah, 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.

And, you know, 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. It's been really a combination, both of those companies putting those plans together, making them compelling for their shareholders, and then the right policy support from the federal and provincial governments to create the egress options for that bitumen. And 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 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 with time given that backdrop.

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