OVV

Good day, ladies and gentlemen. Thank you for standing by. Welcome to Ovintiv's 2026 second 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. 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 second quarter 2026 conference call. This call is being webcast. The slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the beginning of our slides and our disclosure of documents filed on EDGAR and SEDAR+. Following prepared remarks, we will be available to take your questions. I will now turn the call over to President and CEO Brendan McCracken.

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

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

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

Our net debt was below $3 billion at the end of the quarter, marking the lowest leverage the company has had in over a decade. Our capital structure has been 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 1x, and a strong outlook for the rest of the year, we have the capacity to buy back a substantial number of shares and continue to advance our ground game strategy. We have assembled one of the most valuable premium inventory positions in our industry.

Since 2023, we've increased our Permian and Montney drilling inventory by more than 3,200 locations at an average cost of $1.4 million per net 10,000 ft location. We did it without diluting our shareholders or stressing our balance sheet. Our work to build inventory depth means that we have nearly 15 years of premium inventory in the Permian and close to 20 years of premium oil inventory in the Montney. This expansion has been unmatched by our peers. In fact, over the same time period, most companies saw their inventory life decline.

Our goal now is to maintain our premium inventory 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.

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. 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 Montney. 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 18-24 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. 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 Simul-frac and Trimul-frac, advancements in stage architecture design, wet sand, proppant intensity, and surfactant usage. The implementation of any one of these items often builds on or depends upon the previous implementation of another.

Today, our frontier innovations are powered by AI to leverage our extensive private well data set, optimize our technical workflows, and operational execution in real time. We are using this new technology across our portfolio. This has led to faster cycle times, 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 bpd above the high end of our guide, with total volumes coming in at 615,000 BOEs per day. The oil and condensate beat was driven by the Permian, where we continue to see strong new well results as well as outperformance from our base production. We successfully navigated some extended downtime in the Montney due to a series of planned plant turnarounds.

The impact on our condensate volumes was minimal, as we were able to prioritize flowing our most liquids-rich wells. This meant we came in below the low end of our guidance for natural gas volumes. The revenue impact of the lower gas volumes was negligible, as AECO prices were quite weak during the quarter. The turnarounds were all completed during Q2, and we expect our Montney production volumes to be more stable through the second half of the year. We also reduced net debt by about $3.4 billion using the proceeds from our Anadarko disposition as well as a portion of free cash flow.

The resulting quarter end net debt balance was $2.995 billion, bringing our leverage ratio to 0.6x. This is a major milestone for us as debt reduction has been a key focus for several years. The stronger capital structure also resulted in Fitch upgrading our credit rating to BBB from BBB 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 bpd 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're raising the Permian's go-forward run rate to 125,000 bpd and our full-year total company oil and condensate production guidance to 210,000-212,000 bbl/d. When combined with year-to-date share buybacks, this equates to oil growth of about 4% on a per share basis with no additional capital.

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

We're not currently seeing significant inflationary pressure on our 2026 capital program outside of higher diesel costs. We expect to offset any additional cost inflation with operational efficiencies. Our full-year capital guidance remains unchanged. In the third quarter, we expect production to average approximately 628,000 BOEs/d, including about 208,000 bbl/d of oil and condensate, our capital spend is expected to come in at around $575 million, consistent with the second quarter. Activity in both assets is expected to be fairly ratable for the rest of the year. I'll now turn the call over to Greg, who'll speak to our operational highlights.

Thanks, Corey. Across our acreage footprint, our Permian well productivity continues to be strong. Year-to-date performance has exceeded our type curve, which is unchanged from last year. With average second quarter oil and condensate volumes of 127,000 bbl/d extending the outperformance we saw in Q1, we're increasing our expected run rate in the play to 125,000 bbl/d. 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 volume selling into Waha, we avoided the deeply negative price realizations experienced by some of our peers. Our Permian productivity uplift is coming from both our new wells and our base production. This is thanks in part to our cube development approach and reoccupation timing, as well as the benefits of stacked innovation. Using public data from Enverus, you can see that our Midland Basin wells continue to significantly outperform the peer average. They have gotten better every year since 2023, and our 2026 year-to-date results really stand out.

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

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

Moving north now. Despite some noise during the quarter from plant turnarounds and higher royalty rates, our Montney well productivity continued to be very strong, tracking above our 2026 type curve. The plant turnarounds are now behind us. 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. While higher condensate prices did result in higher royalty rates, the revenue uplift far outweighed the impact of lost volumes.

Our realized price for the Canadian condensate was about $94, which was a premium to WTI. Although we don't like losing the reported volumes, we remain focused on the bottom line. Based on current strip pricing, for the second half of the year, we expect our Montney condensate volumes to average 80,000-85,000 bbl/d. Also of note was our Montney gas price realization at 187% of AECO. Our diversified portfolio of both physical sales out of the basin and financial arrangements to price our gas away from AECO continues to be highly valuable. Uniquely this quarter, our realized gas price was boosted by sulfur revenue.

Sulfur is a byproduct of our gas production in certain areas across our Montney acreage. Typically, it is an expense to extract this product from our gas stream and transport it to the West Coast market. In the second quarter, however, sulfur prices were historically high and contributed about $40 million in revenue. It's hard to predict where prices will go over the longer term, we do expect sulfur prices to remain strong for the rest of the year. Our Montney team continues to push the boundaries on cycle time improvements.

Year-to-date, our completion speed averaged more than 4,900 ft per day, or about 20% faster than our 2023 performance, and about 40% faster than the current pace of our Montney peers. We recently established a pace setter of more than 7,000 ft of completed lateral length per day using Simul-frac. We are very excited to test the repeatability of this result over time. We also achieved an industry milestone with the first ever 100% domestic wet sand pad in Canada. This is another example of stacked innovation that we've successfully transferred between assets. Compared to importing dry sand to the Montney, domestic wet sand is roughly 20% cheaper.

The combination of faster cycle times and consistently strong well performance with innovations like wet sand results in industry-leading capital efficiency and highly competitive returns. We have long been believers in the benefits of diversification when it comes to managing natural gas price exposure. We utilize a variety of structures, both physical and financial, to price our gas away from the oversupplied AECO and Waha hubs. We have the least AECO exposure of our Montney peers, the most diversified portfolio of market access, and consistently realize a material premium to in-basin pricing.

We also have one of the highest gas price realizations among our Permian peers. We price more than half of our gas outside of Waha, with exposure to GCX, Whistler, Matterhorn, and starting later this year, the Hugh Brinson Pipeline. The result is that despite producing gas in 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 Montney, 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 a 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.

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. Neil Mehta with Goldman Sachs, please go ahead.

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

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

It is a real system. What we find is each of these factors are interrelated and affect the others, so the holistic design matters. 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. Defining those causal relationships is what's really valuable in the subsurface, particularly on productivity and recovery. That's the fundamental basis. If you think about your point on there's no trade secrets or intellectual property in the Permian, I think that's true of the industry overall. Because we get on calls like this and talk about all the recipe that.

Really where the moat comes from, the competitive moat that we've been able to build is the whole system here. 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. 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.

You can't replace the years of experience that allow us to perform the logistics, the supply chain, and the engineering geoscience to know what the right thing to do is. That's all institutional knowledge that while the headlines are available and knowable, the details of how to go do that as a company at scale are actually really hard to mimic and duplicate. The final thing is the private data, where we've assembled a very large, we believe, unique private data set across both the Montney and the Permian that allow us to establish those causal relationships with confidence and then be able to incorporate them into our designs at scale. That's I think the answer to your question.

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

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

That is all news and constructive. We'll obviously have to wait and see for that comment period to conclude and see what their final decisions are. But if you take their proposed methodology, which would have a 50% weighting for companies like Ovintiv, that would imply we've seen some analysis even just in the last 24 hours here from several of the banks that have been following this. We've seen anywhere from 3 million-7 million shares of direct buying from the index funds.

Then of course, we would expect some active buying that could be multiples of that coming from the active managers that we would now be in their benchmark. All of this is constructive for us and I think comes at a great time for us as well because a lot of interest in what we've created here and from the Canadian investor and then as well at least a couple of Montney players that are going away through transactions, one of which was NuVista that we acquired and then ARC is the other one with Shell. Definitely all a tailwind for us.

Thanks.

Thanks, Neil.

Greg Pardy with RBC Capital Markets, please go ahead.

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

Greg, appreciate the question. It's a good one. We are very early stages in the Montney. We've been relatively advanced in the Permian. This year, almost every well is going to have a surfactant treatment. In the Montney, we're just really getting started there. 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 Montney. I don't think it's imminent to have a conclusion on the efficacy in the Montney, but definitely going to be able to accelerate relative to the pathway we took in the Permian. We're building on that knowledge and applying it up north, which is really exciting.

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

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

Like you said, lots of free cash flow to enable the combination of buybacks and then, we have also said the ground game can be funded out of that free cash flow as well. I would comment specifically on that to say you should expect something in the modest size deals. We think we've got line of sight in both the Permian and the Montney to do deals like that at very attractive entry points from $1 per location perspective, which has been our track record here. You should think about that ground game being in the low hundreds of millions of dollars type of range.

All right. Very good. Thanks very much.

Thanks, Greg.

Neal Dingmann with William Blair, please go ahead.

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

Yeah. We're early days, and excited about that. I think we're early days in both places, to be honest. I think this stack just grows with time. Turn it over to Greg to provide some color on that.

Yeah. Appreciate the 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. Things like cube development and spacing and stacking, we've been doing that in both the Permian and the Montney for, gosh, a decade now. Things like Simul-frac, wet sand, 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 Montney.

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

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

Great question, Neal. The T&P, if you look at how it's broken out by country, the majority of it is in Canada, in our Montney operation. 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. 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 business, fully realized, and that this is the longer-term mission is to go find some more profitability by combining those positions together. One of those big buckets is going to be around the T&P. We do expect this to unfold over time. This is probably going to be a multi-year process for us. It's not an overnight thing. We don't have specific guidance baked into this year. The message is we're very focused on this as an opportunity to drive free cash flow growth going forward.

Thanks for the details, Brendan.

Yeah, great. Thanks, Neal.

Arun Jayaram with JPMorgan, please go ahead.

Good morning, team. Brendan and Corey, you guys have raised your second half Permian crude and condensate guidance to 125,000 bbl/d versus the previous messaging around 120 as being kind of the run rate. Should we perceive this as the go forward call maintenance kind of or sustaining production rate in the Permian? I was wondering if you could just unpack that a little bit.

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

Yeah. Thanks for the question, Arun. Yes, first off, we are saying 125 is the run rate go forward in the asset. 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. This run rate is assuming a level loaded program in the Permian, so we're not adding more activity or more capital. 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. More importantly, we've seen that really good performance across the portfolio. We're seeing strong results from our new wells in all of the areas that we have in play. That performance has given us a lot of confidence. The other thing that's probably the most exciting is how that performance has persisted over time and is translating into stronger base performance. Not only good new well performance, but the base is very strong on some of those newer wells. The team has really put a lot of effort into some of our older wells. Working on the base, through our operations control center there in Midland, we've been able to improve run times from our ESPs.

We've 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 minimize failures, optimize production. When we do have failures, we're able to get our wells back online quicker with some of the automation that the team's put in. All of that results in fewer zero days, which shallows declines. It really helped the base. It's going to be a combination of the new well performance, the base performance, all of that coming together gives us confidence and that's what allowed us to say we're going to be at 125 run rate going forward.

Great. Thanks, Greg. Just a quick follow-up. In terms of the Montney well productivity in 2026, I was wondering if you could maybe speak to maybe some of the drivers of that. Sounds like surfactants are maybe not quite the driver, but I'm thinking maybe a little bit of mix between maybe some of the new properties, a little bit more activity at Karr, Wapiti. Just maybe give us a sense of what's driving that.

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

All the things that we've done in the Permian, we're doing those same things up in the Montney and just seeing really strong well results across the portfolio. We've leaned in on density a little bit on some of the newer properties down in Wapiti and Karr. Those density tests are also performing as expected in most cases, and then some of the zones are actually doing a little better in the deeper zones down in the Sexsmith. We're very pleased with results across the portfolio in Canada and expect that to continue.

Great. Thanks, Greg.

Thanks, Arun.

Doug Leggate with Wolfe Research. Please go ahead.

Good morning, guys. Thanks for having me on. I got two, Brendan, if you don't mind. One for Greg, or perhaps it's for you, and one for you, or perhaps it's for Corey. My first question is on the proppant and the wet sand and the clear impact this is having on what appears to be your decline curves. That over time would imply that your capital efficiency is improving and your sustaining capital would theoretically decline unless you take the higher production. My question is, do you maintain the activity, maintain the spending, or do you take the efficiency, flatline the production, and have lower spending? You get what I'm getting at. Either do you beat the numbers-

Yeah.

...or do you cut the capital?

Yeah, it's a great question, Doug, and it is one that we think about. 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.

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, also, the buybacks on the denominator side. 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.

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

You're now sitting at $17 and change $1 billion market cap with $3 billion of net debt. That's $20 billion of enterprise value. It means you're essentially discounting a $2 billion free cash annuity with a $2 and change capital program. That's the $4 billion cash flow number that you gave us last quarter to justify your buyback on the basis of value. You're basically there. And your swing in the share price in the last two months is $11. Why not take this windfall and hit the net debt? What you justified is the basis of your valuation. Unless you've changed your oil price view, you're basically there.

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. 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. 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. 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. Clearly, we agree with the thesis of running these businesses at low leverage. I think your note called it a top quartile amongst peers leverage company now. That's been our ambition. We're pleased to have gotten it here. I think we're taking a prudent and balanced approach with the capital allocation.

More a net debt issue than a debt issue, but I appreciate the answer, Brendan. Thanks.

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

All right. We'll take it offline. Thank you.

Thanks, Doug.

Gabe Daoud with Truist, please go ahead.

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

Yeah. I'll pass over to Greg here, Gabe. One thought, just quickly to set that up, because there's been a couple of questions overnight. The Barnett position, the 100,000 acres of Barnett that we disclosed last quarter is all on existing acreage. There's been no transaction there. This was in our acres that we've held in the play for a decade plus here now. 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 $1. Greg can talk about where we're at on our Barnett well.

Great. Thanks, Brendan. Thanks, Gabe, for the question. As an industry, we're learning a lot about the Barnett right now. As you see, there's a lot of activity going on throughout the basin, drilling wells, bringing them online. We're seeing a lot of data from our peers that are operating around our position that has given us encouragement. As Brendan mentioned, these are held acres, so we don't have to go out and drill wells today, but we are excited to continue to learn more. We've already started drilling our first well. We've drilled and cored the vertical. The core looks very encouraging.

This is a well in Martin County that we're doing currently. 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. That also gives us a lot of trade currency. We can trade that core well data with our peers to learn more about what they're learning here. We're also participating in really small working interests with some peer wells.

We do have a growing data set that we're learning from. We are taking the approach generally that we're going to watch others try to delineate where the different product windows are in the play and help us learn what costs are ultimately going to be. 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.

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

Gabe. Thank you. Look, super encouraged. I think the market continues to develop. Our strategy is to continue to diversify our gas sales away from AECO. 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. All of this is constructive for our ability to diversify our gas away from AECO. More of the same there, and I think Greg and Corey did a good job of highlighting the benefit we're already seeing from that strategy in our gas realized prices.

Definitely. Awesome. Thanks, Brendan.

Yeah. Thanks, Gabe.

Scott Gruber with Citigroup. Please go ahead.

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

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

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

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

Yeah, great question. In addition to using electric frac fleets in the Permian, we also have a natural gas-fired frac fleet operating in Canada, so we've totally displaced the diesel up there. A number of our drilling rigs are dual fuel. They 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-fired generation that we're using out in the field and gotten on grid power there. Just across the portfolio, looking for ways to reduce the amount of diesel required.

Our wet sand mines that we're using in the Permian and starting to use in the Montney, that eliminates truck miles. That's one of our biggest pass-through costs, is when transportation has to pass through the diesel cost. It's really across the board, but by using less diesel, we have less exposure there. Again, any inflation we're seeing due to those diesel pass-through charges, we're offsetting that with efficiencies. We've been able to do that successfully year-to-date, and I think we'll be able to do that going forward as well.

I appreciate the color. Thank you.

Thanks, Scott.

Chris Baker with Evercore ISI, please go ahead.

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

Yeah. Great question, Chris. I think the exciting news today is the growth with no capital or activity. That's kind of the first port of call as we start to think about 2027. We are also continuing to think about when might be the right time to invest for growth. Premature yet to say for 2027. Obviously, going to watch some water come under the bridge on the global fundamentals. I would say within that, we're obviously all watching the same news flow out of the Gulf. We're also watching closely to see where is Chinese demand going to normalize.

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. Really, again, our orientation will be around value. Where can we create the most value and return on invested capital? 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. We will also weigh that investment against the buybacks that today continue to look really attractive from a per share perspective. I think no change to our approach or philosophy, just trying to make it with the best information we have on hand.

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

Yeah, I think obviously the more data we accumulate, the more we study that. For now, the guide makes sense, and it's the right go-forward way to model the company. We're always looking for ways to improve it, and that's been the track record here. We'll get to that in time as we work our way through the rest of this year and into next. 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.

Great. Thanks, guys.

Thanks, Chris.

John Annis with Texas Capital, please go ahead.

Good morning, all, and thanks for taking my questions. For my first one, the pace setter Simul-frac operation achieved completion speeds of more than 7,000 ft a day, while the domestic wet sand pad reduced sand costs by 20%. My question there is, how repeatable are these results? What percentage of the Montney program could ultimately adopt each, and over what timeframe?

Yeah, John, thanks for the question. I'll pass over to Greg. Historically, our approach has been to think about those pace setters as our target to convert to average. The idea here is for the team to be able to show, hey, if we can do it once, why can't we do it every time? 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. Greg, you can dig in a little deeper there.

Yeah, for sure. Starting with the Simul-frac, really the only limitation there is pad setup and logistics. I would say almost all of our operations in the Montney set us up well for Simul-frac. 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, the mines are just starting to ramp up. There is a lot of activity in that space, I think, over the next year or two, you're going to see more domestic sand options.

As they're putting in those sand mines, we're actually allowing them to save quite a bit of capital if they don't put in a dryer and just supply wet sand. 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. Realistically, that's probably 2028-ish kind of timeframe it'll take. This year, we're at 50% domestic sand, with a portion of that being wet. Next year, I would anticipate that growing, but we're still probably a couple years away from getting to a fully implemented program like we have in the Permian.

I appreciate that color. For my follow-up, you've already organically replaced locations planned for 2026 in both the Permian and Montney. How much additional opportunity do you see to expand inventory through similar technical work, and should we expect organic additions to continue offsetting annual drilling activity over the next several years?

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

It's never going to be completely ratable. We're going to have to sort of work on those over periods of time, but it seems to be continuing. There doesn't seem to be a stop to it. 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.

Thanks, guys.

Yeah. Thanks, John.

Kevin MacCurdy with Pickering Energy Partners, please go ahead.

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

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. As we go through it, I mean, we've got our ongoing forecast, what we think our free cash flow is going to be, 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. It's really just a combination of being in the market regularly also adjusting daily if there's something going on.

Appreciate it. That's it for me.

Thanks, Kevin.

[inaudible] Please go ahead.

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

Hey, [inaudible] Great questions. The 100,000 per well has been part of this stacking process over the last several years. Just to give you the under the hood, when we started, the treatment costs were in that $500,000 a well range that we've heard about from other operators. 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. By the way, some surfactants make productivity go down, was our big learning in the lab. Be very careful about the chemistries that you choose to deploy at scale in the field.

When we started $500,000 a well, got some surfactants that were delivering results in the lab, trialed them in the field, proved them up, then went back to the lab and worked on substitutes that would allow us to lower the cost. That whole iterative journey has led us from that $500,000 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. That, I think, has been part of the advantage. It does take time, of course, and a well-established protocol to do that.

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. You see that in our updated production guide, with the base being one of the big contributors. 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 well. Final comment, just to totally blow the question out, would be that the one thing we haven't data traded is our surfactant stuff. We've chosen to keep that one privileged to ourselves for now.

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

Yeah, it's a really good question and quite timely. 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. Since that time, we've seen just a dramatic shift. 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, kind of 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. All of that to say, there now appears to be quite a list of shovel-ready growth projects in the oil sands for growth. If you think about it, for every 1 million barrels a day of bitumen growth, that equates to about 300,000 bbl/d of new condensate demand for diluent.

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.

Sounds great. Thanks, guys.

Yeah. Thanks.

At this time, we have completed the question and answer session. 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.