Operator: Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 26 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 1. For members of the media attending in a listen-only mode today, you may quote statements made by any of your Ventev representatives. However, members of the media who wish to quote others who are speaking on this call today we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded. Or rebroadcast without the expressed consent of Ovintiv. I would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.
Jason Verhaest: Thanks, Joanna, and welcome, everyone, to our second quarter 26 conference call. This call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward looking statements at the beginning of our slides and our disclosure documents filed on EDGAR and SEDAR plus Following prepared remarks, we will be available to take your questions. I will now turn the call over to our President and CEO, Brendan Michael McCracken.
Brendan Michael McCracken: Thanks, Jason. Good morning, everybody, and 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 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 dataset 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 1 of the most innovative, efficient, opportunity-rich E&Ps in North America, and we are very excited to be operating from this position of strength. Both our Permian and our Montney year to date results are tracking above type curve. and continue to lead the league in their respective basins. This is driving an increase to our full year oil production guidance, which equates to about 4% growth on a per share basis. With no additional capital or activity. Our cash flow per share and free cash flow both beat consensus estimates by 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 substantial number of shares and continue to advance our ground game strategy. We have assembled 1 of the most valuable premium inventory positions in our industry. Since 2023, we have increased our Permian and Montney drilling inventory by more than 3.2 thousand locations, at an average cost of $1.4 million. Per net 10 thousand foot location and we did it without diluting our shareholders or stressing our balance sheet. Our work to build inventory depth means that we have nearly 15 years of premium inventory in the Permian, and close to 20 years of premium oil inventory in the Montney. This expansion has been unmatched by our peers. In fact, over the same time period, most companies saw their inventory life decline. Our goal now is to maintain our premium inventory 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 have 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. 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 dataset. And we have built institutional capability to execute on the leading edge. Our culture, our expertise, our private data combined together are hard to do, 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 US shale trend of performance degradation. We have deliberately taken a different approach than many of our peers. The result is that we have-- we are consistently 1 of the highest oil productivity lowest cost operators in both the Permian and the Montney. We have over a decade of experience deploying our systematic cube development approach. Which means we codevelop multiple stacked zones from a single pad. This creates value by maximizing both returns and resource recovery. We also have around 5 years of experience deploying our reoccupation strategy. We have found that the optimal timing to drill an adjacent cube is roughly 18 to 24 months after drilling the first. This minimizes pressure depletion from the first cube into the next and is a dominant driver of our development schedule. As a result of our cube development in combination with our reoccupation timing, Each annual program samples wells from across our rate of return increment 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 are 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 1 of the lowest costs consistently is a slam dunk combination. The completion space has been the source of several cost and product enhancing innovations. Such as Simulfrac and Trimulfrac. Advancements in stage architecture design, wet sand, proppant intensity, and surfactant usage. The implementation of any 1 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 dataset, 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 is what enables us to identify, test, and scale innovation rapidly across our portfolio. While maintaining cost and productivity leadership. I will now turn the call over to Corey, who will speak more to our second quarter results and our guidance updates.
Corey Douglas Code: 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 thousand barrels per day, above the high end of our guide. Total volumes coming in at 615 thousand BOEs per day. The oil and condensate beat was driven by the Permian. We continue to see strong new well results as well as outperformance from our base production We successfully navigated some extended downtime in the Montney, due to a series of planned plant turnarounds, the impact on our condensate volumes was minimal as we were able to prioritize flowing our most liquids rich wells, but this meant we came in below the low end of our guide 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 triple b from triple b 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 of what we can achieve through the second half. We have seen consistent outperformance from our Permian asset relative to the 120 thousand 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 of 125 thousand barrels per day. And our full year total company oil and condensate production guidance to 210 thousand to 212 thousand 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 thousand and 85 thousand barrels per day. Our full year NGL guidance is also increasing to about 84 thousand barrels per day, and we are maintaining the midpoint of our previous natural gas guidance at 2.05 Bcf per day. Our portfolio has deep inventory duration and the capability to further grow top line production in both assets, However, we believe it is still prudent to maintain efficient, level loaded programs in both the Permian and the Montney and that higher oil prices accrete to free cash flow versus investing in drilling more wells. We are not currently seeing significant inflationary pressure on our 2020 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 thousand BOEs per day including about 208 thousand barrels per day of oil at condensate and our capital spend is expected to come in at around $575 million. Consistent with the second quarter. Activity in both assets is expected to be fairly ratable for the rest of the year. I will now turn the call over to Gregory, who will speak to our operational highlights.
Gregory Dean Givens: 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 thousand barrels per day extending the outperformance we saw in Q1, we are increasing our expected run rate in the play to 125 thousand barrels per day. We realized strong Midland oil prices this quarter, which traded at 7% premium to WTI. Our U. S. Oil volumes also benefited from the WTI role which added about $5 to our oil price realizations. Our Permian gas also benefited from relatively strong Houston Ship Channel price 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 have now completed about 400 Permian wells with surfactants since 2019. We see about a 9% improvement in oil productivity versus a nonsurfactant treated well. We think surfactants account for roughly half of productivity uplift we have seen over the last few years. At a cost of only $100 thousand 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 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 am very proud of the way the team was able to limit the impact on our most liquids rich wells. Especially given the strength of condensate prices during the quarter. And while higher condensate prices did result in higher royalty rates, the revenue uplift far outweighed the impact of lost volumes. Our realized price for the Canadian condensate was about $94. Which was a premium to WTI. Although we do not 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 thousand to 85 thousand barrels per day. Also of note was our Montney gas price realization in a 187% of AECO. Our diversified portfolio of both physical sales out of the basin financial arrangements to price our gas away from AECO continues to be highly valuable. Uniquely this quarter, our realized gas price was boosted by sulfur revenue. Sulfur is a byproduct of our gas production in certain areas across our Montney acreage. Typically, it is an expense to extract this product from our gas stream and transport it to the West Coast market. In the second quarter, however, sulfur prices were historically high and contributed about $40 million in revenue. While it is 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 4.9 thousand feet per day or about 20% faster than our 2023 performance. And about 40% faster than the current pace of our Montney peers. We recently established a pacesetter of more than 7 thousand feet of completed lateral length per day using Simulfrac. 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 have successfully transferred between assets. Compared to importing dry sand to the Montney, domestic wet sand 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 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 1 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 Hub-to-Benson pipeline. The result is that despite producing gas in 2 of the weakest price basins in North America, our gas is generating significant revenue. During the quarter, our total company gas price realizations, hedging, was $1.99 per Mcf. Or about 70% of NYMEX. We will continue to pursue opportunities to further diversify our gas price exposure over time. I will now turn the call back to Brendan.
Brendan Michael McCracken: Thanks, Greg. Halfway through the year, we have generated more than $1.3 billion of free cash flow. Organically replaced our full-year 2026 drilling locations in both Permian and the Montney, brought our debt down below $3 billion and are set to grow oil production per share by 4% with no increased activity or capital spending. Our execution continues to lead the industry, underpinned by culture, expertise, and data. Our portfolio is best in class. Our balance sheet is rock solid. And our stacked innovation and disciplined approach to capital allocation are driving compelling returns. This concludes our prepared remarks. Joanna, we are now ready to open the line for questions.
Operator: Thank you. Ladies and gentlemen, as a reminder, you can join the queue to ask a We will now begin the question and answer session and go to the first caller. Neil Mehta with Goldman Sachs. Please go ahead.
Neil Mehta: Hey, Brendan and team. Thanks for the update. And obviously, really impressive results. I just wanted to focus on Slide 12 here. And give you an opportunity to unpack some of these stacked innovations that are driving this productivity improvement And in particular, the surfactants seem to really be driving a lot of this upside. So can you just talk about some of the technologies that are at work here? Which ones are you most excited about? And what is the sustainability of the advantage? Because, you know, the old adage, there are no secrets in the Permian is something. That I there is some truth to Yeah.
Brendan Michael McCracken: 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 have we have been pegging it at about a 9% uplift on our type curve, so obviously really important, but far from the whole story. And that is why we have 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 cracks 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 is Really Valuable In The Subsurface Particularly On Productivity And Recovery. So that is The Fundamental Basis. If You Think About Your Point On there is No Trade Secrets Or Intellectual Property In The Permian, I think that is true of the industry overall. Because, you know, we get on calls like this and talk about all the recipe that And so, really, where the moat comes from, the competitive moat that we have been able to build is the whole system here. And that is why we have 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 is 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 have created this institutional capability to be able to execute at this leading edge and that is really valuable. Like, you cannot 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 is 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 have assembled you know, a very large, we believe, unique private dataset across both the Montney and the Permian. That allow us to establish those causal relationships with confidence. And then be able to incorporate them into our designs at scale. So yeah, that is that is I think the answer to your question.
Neil Mehta: that is really impressive. And then, Brendan, I do not 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 are having or how you are-- how you are thinking about that potential as that could change the shareholder base and be a catalyst for the story?
Brendan Michael McCracken: Yeah. Yeah. it is a great point. there is some news just this week actually on that front. So S and 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 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 18 event. So and in that comment, process, they have specifically called out Ovintiv as 1 of 3 companies that would meet the proposed criteria for eligibility to be included into the TSX. So that is all news and constructive You know, we will 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 have seen some analysis even just in the last 24 hours here from several of the banks that have been following this. We have 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 that could be multiples of that coming from the active managers that are we would now be in their benchmark So all of this is constructive for us, and I think comes at a great time for us as well because, you know, a lot of interest in what we have created here and from the Canadian investor, and then as well you know, at least a couple of Montney players that are going away through transactions. You know, 1 of which was NuVista that we acquired, and then ARC is the other 1 which Shell. So definitely all a tailwind for us. Makes sense. Thanks, Neal.
Operator: Greg Pardy with RBC Capital Markets. Please go ahead.
Greg Pardy: Yeah. Hey. Thanks. Thanks. Good morning. I wanted to take 1 maybe just to build on what Neil was asking about. But how much of the difference is there in terms of the implementation of surfactants in the Permian versus the Montney. And then I am just curious as to maybe what you know, at what stage have you begun to implement it in it in the Montney, or is it very, very early stages there?
Brendan Michael McCracken: Yeah. Great Appreciate the question. it is a good 1. So we are very early stages in the Montney So we are we are we have been relatively advanced in the Permian This year, almost every well is gonna have a surfactant treatment. And then in the Montney, we are just really getting started there. So the lab results are very encouraging. If you think about you know, 4 or 5 years of cycle time in the Permian, we are gonna be able to accelerate that in the Montney. You know? So I do not think it is imminent to have a conclusion on the efficacy in the Montney, but definitely gonna be able to accelerate relative to the pathway we took in the Permian and so we are building on that knowledge and applying it up north, which is which is really exciting.
Greg Pardy: Okay. Alright. Listen. Thanks for that. And then I am just trying to I am trying to reconcile shareholder returns, the balance sheet, dividends. I mean, you are in an awfully good place now. Right? The net debt is has really been slayed I am curious as to, you know, maybe what you kinda think about as being an optimal capital structure. And then, you know, believe you said you are kind of 45% in terms of shareholder returns in the first half. that is gonna be 60%. But, I mean, if your shares are trading at the discount they are vis-à-vis intrinsic I think we would agree with that. Then, you know, do we see a big emphasis on buybacks as we go through the back half of the year? Or do you still think that there is some room? it is probably a better question for Corey, but do you still think there is some room for net debt reduction?
Brendan Michael McCracken: Yeah. I think you painted it out there, Greg. I think you know, obviously, we do not have a crystal ball on exactly where commodity prices are gonna go from here. it is been a dynamic last few months and even last couple of weeks here. So we are 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 is why you seeing us lean in from the roughly 45% year to date to the to the signaling that is gonna be at least 60 or 60 or greater for the rest of the year. So or for the full year. And so from a capital structure perspective, we feel really good about the capital structure that we have we have created in the business today. So 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 gonna be the modest size deals. Think we have got line of sight in both the Permian and the Montney to do deals like that. At very attractive entry points from a 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. Alright. Very good. Thanks very much. Thanks, Greg.
Operator: Neal Dingmann with William Blair. Please go ahead.
Neal Dingmann: Thanks for the time. Good morning, Brendan. Brendan, my first question just around what I would call your very appropriate described stacked innovation approach. Specifically, have you all applied this approach now fully or started I guess, you are even started applying this approach to the Montney. And if so, you know, if you have not yet fully yet do you plan to do you and Gregory plan to do that in the coming quarters?
Brendan Michael McCracken: Yeah. So we are we are early days. And excited about that. I think we are early days in both places, to be honest. I think the stack just grows with time. But, you know, turn it over to Gregory to provide some color on that.
Gregory Dean Givens: Yeah. Appreciate the question. I think if you think about all of the stacks, that you see there on slide 8, each 1 of those is the culmination of years of work in each 1 of the plays. So things like cube development and spacing and stacking, we have been doing that in both the Permian and the Montney for, you know, gosh, a decade now. But things like Simulfrac, wet sand, you know, that is had different levels of application in each of the 2 plays. We continue to improve how we do that in the Permian, and I think we are a little earlier in the process on how we are doing that in the Montney. As we just reported, you know, our first wet sand full wet sand trial in the Montney this quarter. It went very well. We think we are gonna lean into that more as we go throughout this year and into next year. We will take a little bit of time for the infrastructure to catch up there. But so we are different places with each of the technologies. I think the 1 I am most excited about is the AI the new digital tools we have 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 and on the stack but, applying it across the board, and there is still room to go from here.
Neal Dingmann: Makes sense. Thanks, Greg. And then, just second my second question is really diving in on the Montney GP and T. Specifically, could you talk about potential future GP and T cost savings? I mean, it assumes now that given you have such a massive position now with you know, after adding NuVista and Paramount, you know, what type of potential is there to reduce GP and now that you have such a such a large position up there?
Brendan Michael McCracken: Yeah. Greg great question, Neal. The TMP, if you look at how it is broken up by country, the majority of it is in Canada in our Montney operation. And so, what we are excited about here is we have really just getting going with the 3 positions being combined together That is our legacy position, the Paramount position and then the NuVista position. And when if you remember when we did those deals, we signaled, hey. there is a bunch of tangible synergies we are gonna 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 1 of those big buckets is gonna be around the T&M. So we do expect this to unfold over time. it is probably gonna be a multiyear for us. it is not an overnight thing. And so we do not have specific guidance baked in to this year, but the message is we are very focused on this as an opportunity to drive free cash flow growth going forward. Thanks for the details, Brendan. Yeah, Greg. Thanks, Neal.
Operator: Arun Jayaram with JPMorgan. Please go ahead.
Arun Jayaram: Yeah. Yeah. Good morning, team. Brendan and Corey, you guys have raised your second half Permian crude and condensate guidance to a 125 thousand barrels a day versus the previous messaging around 21 as being kind of the run rate. I was wondering if should we perceive this as the go forward call maintenance kinda or sustaining production rate in the Permian. Was wondering if you could just impact that a little bit.
Brendan Michael McCracken: Yeah. I am gonna let Gregory take the win on this 1, because it is really his team that delivered that for us, Arun. Yeah. Go ahead, Gregory.
Gregory Dean Givens: Yeah. So thanks for the question, Arun. And, yes, first off, we are saying a 125 is the run rate go forward in the asset. So not just the rest of this year, but beyond. As we think about, we got there-- first, I 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 are not adding more activity or more capital. But, you know, over the last several quarters, we have been talking about some really exceptional results we have seen in the northern Midland Basin from some of the Dean Wells there. I know that performance has persisted But more importantly, we have seen that really good performance across the portfolio. We are seeing strong results from our new wells and all of the areas that we have in play. And so that performance is giving us a lot confidence. But the other thing that is 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. It was 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, we have been able to improve run times from our ESPs. We have 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 are 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 it really helped the base. So, you know, it is 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 is what allowed us to say, you know, we are gonna be at a 125 run rate going forward.
Arun Jayaram: Greg. 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. It sounds like surfactants are maybe not quite the driver, but I am thinking maybe a little bit of mix between maybe some of the new properties, a little bit more activity at Carr, Wapiti. Just maybe give us a sense of what is driving that Yeah.
Gregory Dean Givens: I will take that 1, Arun. Know, we have actually seen really strong results across the entire position. We have had really strong results in our legacy wells up in Dawson, We have had some good pads in Pipestone as well as areas like Karr and Wapiti that are newer to the portfolio. So we have seen really strong results that you know, a result of those stack innovations. We have been working on our stage architecture. We have been looking at proppant intensity. All the things that we have done in the Permian, we are doing those same things up in the Montney and just seeing really strong well results across the portfolio. We have 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 Sexsmith. So we are we are very pleased with results across the portfolio in Canada and expect that to continue. Greg. Thanks, Greg.
Operator: Thanks, Arun. Douglas Leggate with Wolfe Research. Please go ahead.
Douglas Leggate: Hello. Good morning, guys. Thanks for having me on. I got 2, Brendan, if you do not mind. 1 for Gregory or perhaps it is for you, and 1 for IU or perhaps it is for Corey. But so my first question is on the proppant and the wet sand and the clear impact this is having on what appears to be your decline curves. that, over time, would imply that your capital efficiency is improving and your sustaining capital would theoretically decline unless you take the higher production. So my question is, do you maintain the activity, maintain the spending, or do you take the efficiency flatline the production and have lower spending. You get new 1 getting at. You either do you beat the numbers Yeah. Or do you cut the capital? Yeah.
Brendan Michael McCracken: it is a great question, Douglas. And it is 1 that we think about. And if you look at our history over the last several years, we have 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 it a lot of sense. that is what you have seen us do. And then equally, at a couple of instances over the few years when commodity price have been lower, we have pocketed the capital savings and created more free cash that way. So in this instance, we have done the value creation through the production growth, and that is what you have seen us announce here today with the 4% bump on a per share basis. that is 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 let the benefit accrue to volume growth and free cash flow that way.
Douglas Leggate: Think we will continue to watch. Thank you. I think, Brendan, you would be disappointed if I did not bring up the cash return issue. We all heard Greg's question earlier, and I wonder if I could this is my follow-up. Look, we, like a lot of people, have been very supportive of everything you have done and we worry that at some point, an investment case becomes more about the oil price. Than it does about the company. So here's that was my kind of pre-cursor. But here's my question. You are not sitting at 17 and change billion dollar market cap with $3 billion of net debt. that is 20 billion of enterprise value. It means you are essentially discounting a $2 billion free cash annuity with a 2 and change capital program. that is the $4 billion cash flow number that you gave us last quarter to justify your buyback on the basis of value. So you are basically there. Your net debt is-- and you are swinging the share price in the last 2 months is $11. Why not take this windfall and hit the net debt? Because you are what you justified is the basis of your evaluation unless you have changed your oil price view. You are basically there.
Brendan Michael McCracken: Yeah. Douglas, you cut out 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 are thoughtful about how we allocate capital for best value And so that is why you see us taking the approach we are announcing today. We think the greater than 60% guidance is prudent. We do not 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 is the track record Of course, we are just on the heels, you know, in the quarter that we are releasing today is $3.4 billion of debt reduction. So clearly, we agree with the thesis of running these businesses at low leverage and yeah, I think your note called it a top quartile amongst peers leverage company now. So that is been our ambition. We are we are pleased to have gotten in here. So I think it is I think we are we are taking a prudent and balanced approach with the with the capital allocation. And debt issue, but I appreciate the answer, Brendan. Thanks. Yeah. You bet. The part of that prudence is the value that we see in the shares today. Alright. We will take it offline. Thank you. Thanks, Douglas.
Operator: Gabe Daoud with Truist. Please go ahead.
Gabe Daoud: Thanks. Good morning, everyone. Maybe a question for Gregory. Was wondering if we could maybe get your updated thoughts on the Barnett I know you have that 100 thousand acre position held by production. But curious, what are the plans there? I think you are to be drilling a well there this year, I believe. But curious, Gregory, if there is maybe any update there.
Brendan Michael McCracken: Yeah. I will pass it over to Gregory here, Gabe. 1 thought just quickly to set that up because there is been a couple questions overnight. The Barnett position, the 100 thousand acres of Barnett that we disclosed last quarter is all on existing acreage. So we did not there is been known transaction there This was on our acreage that we have held in the play for a decade plus here now. And so, you know, a real great opportunity for us to work our way into the play in a in a fashion that learns from others. it is a great example of that stacked innovation approach where sometimes we are the ones leading the charge, and sometimes we can sit back and have the benefit of other people's risk dollars. But Gregory can talk about where we are at on our on our Barnett well.
Gregory Dean Givens: Yeah. No, great. Thanks, Brendan. Thanks, Gabe, for the question. You know, as an industry, we are learning a lot about the Barnett right now. As you see, there is a lot of activity going on throughout the basin. Drilling wells, bringing them online. So we are seeing a lot of data from our peers that are operating around our position that just give us encouragement. As Brendan mentioned, these are held acres, so we do not have to go out and drill wells today. But we are excited to continue to learn more. We already started drilling our first well. We have drilled and cored the vertical. The core looks very encouraging. This is a well in Martin County that we are doing currently. And now we are proceeding with drilling the lateral. That well will come online late this year. Which should give us a lot of information around the productivity teach us a little bit about well cost and how efficiently we are gonna 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 are learning here. And we are also participating in really small working interest with some peer wells. So we do have a growing dataset that we are learning from, but we are taking the approach generally that we are going to watch others try to delineate where the difference product windows are in the play and help us learn what costs are ultimately gonna be. But I would not envision us, you know, drilling this 1 well this year, next year, another well or 2. We will see how our progress goes there. But we will be learning all along the way and making sure we optimize our position.
Gabe Daoud: Thanks, Greg. that is great color, and thanks, Brendan, for clarifying that. And then my second question, guys, would just be on the heels of the Pembina-Métis announcement, I guess, a couple weeks or maybe a month ago. Just curious maybe anything to highlight on your efforts on the on the data center front. Thanks, guys.
Brendan Michael McCracken: Yeah, Gabe. Thank you. Look, we are super encouraged. I think the market continues to develop. And what we are ambition or strategy is to continue to diversify our gas sales away from AECO. And so this is another outlet that we are 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 is happening off the West Coast. So all of this is constructive for our ability to diversify our gas away from AECO. So more of the same there, and, you know, I think Gregory and Corey did a good job of highlighting the benefit we are already seeing from that strategy in our gas realized prices. Definitely. Awesome. Thanks, Brendan. Yeah. Thanks, Gabe.
Operator: Scott Gruber with Citigroup. Please go ahead.
Scott Gruber: Yes. Good morning. I wanna come back to the balancing the cash return question and the question about putting, you know, more cash on the balance sheet. As some peers have delevered, you know, they have started discussing a willingness to use their balance sheet during industry sell offs you know, to juice buybacks in order to try to reduce the equity volatility Brendan, is that something that you would contemplate over time, you know, with the balance sheet itself healthy as it is and would you think about, you know, positioning for the balance sheet for that over time?
Brendan Michael McCracken: Yeah. I think it is a good question, Scott. I think certainly something we will be thoughtful about. You know, we are new to this space, so we are excited to be here. But sort of having just arrived here, you know, those are the types of questions that we are asking ourselves. And, yeah, I would not take that off the table. I know, it is obviously down the road. Relative to where commodity prices are today, but we all know that eventuality could occur. So yeah, I think that is something we would put on the table in decisions 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.
Scott Gruber: 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 e frac in the Permian. But curious, you know, what other steps are you taking to try to reduce your diesel consumption know, across your DNC spend?
Brendan Michael McCracken: Yeah. I will let Greg take that 1 on.
Gregory Dean Givens: Yeah. So great question. You know, in addition to using electric frac fleets in the Permian, we also have a natural gas fired frac fleet operating in Canada, so we totally displaced the diesel up there. A number of our drilling rigs are dual fuel. They can operate on natural gas as well as diesel, and so we are ramping up the percentage of natural gas there. We are also looking to, over time, we have eliminated a lot of the diesel fired generation that we are 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 are using in the Permian and starting to use in the Montney, you know, that eliminates you know, truck miles. that is 1 of our biggest pass through costs is when transportation has to, you know, pass through the diesel cost. So it is really across the board, but by using less diesel, we have less exposure there. And, again, any inflation we are seeing due to those diesel pass through charges we are we are offsetting that with efficiencies. So we have been able to do that successful year to date, and I and I think we will be able to do that going forward as well.
Analyst: I appreciate the color. Thank you.
Operator: Thanks, Scott. Christopher Baker with Evercore ISI. Please go ahead.
Christopher Baker: Hey, guys. Thanks for the time. Brendan, know, earlier you talked about you know, pretty dynamic macro environment we would love to hear how you and the team are just thinking about the 2027 growth option that our portfolio provides here?
Brendan Michael McCracken: Yeah. Great question, Christopher. I think the you know, exciting news today is the growth with no capital or activity. So that is just kind of the first port of call as we start to think about 2027. 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 2027, going to have to watch some water come under the bridge on the global fundamentals. I would say within that, we are obviously all watching the same news flow. Out of the Gulf. But we are also watching closely to see where is Chinese demand gonna normalize, you know, and that is a harder thing to know and be certain of, but gonna 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 have 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.
Christopher Baker: Greg. Thanks. And the follow-up, just a lot of great questions already on the stacked innovation. Just kind of putting the pieces together in terms of the higher plateau in the Permian, it looks like the type curve in the slides is pretty much unchanged. Just curious as we think about putting together shallower base decline and the type curve that you guys started the year with here, You know, does continued outperformance and the potential to revisit that type curve represent upside to the guide? Just trying to kinda put those 2 pieces together and how to think about, you know, when and if it might make sense to revisit the type curve.
Brendan Michael McCracken: Yeah. I think I think, obviously, the data we accumulate, the more we study that. But for now, the guide makes sense, and the right go forward way to model the company. But we are always looking for ways to improve it, and that is been the track record here. And you know, we will we will get to that in time as we work our way through the of this year and into next. But for now, the guidance makes good sense, I think. Boosting it up to the 25 is a real value accretion for our shareholders, and we are we are proud to be able to do it. Right. Thanks, guys.
Operator: Thanks, Christopher. John Johnston with Texas Capital. Please go ahead.
Analyst: Good morning, all, and thanks for taking my questions. For my first 1, the pacesetter Simulfrac operation achieved completion speeds of more than 7 thousand feet a day, while the domestic wet sand pad reduced sand cost by 20%. My question there is, how repeatable are these results? What percentage of the Montney program could ultimately adopt each and over what time frame?
Brendan Michael McCracken: Yeah. John, thanks for the question. I will pass it over to Gregory. But historically, our approach has been to think about those pacesetters as our target to convert to average. So the idea here is to for the team to you know, be able to show, hey, if we can do it once, why cannot we do it every time? And our track record has been able to do that pretty reliably. Once we set a pacesetter, we have been able to convert that into our average performance down the road. But Gregory, you can dig in a little deeper there.
Gregory Dean Givens: Yeah. For sure. Yeah. Starting with the Simulfrac, really, the only limitation there is this pad setup and logistics. And so I would say almost all of our operations in the Montney set us up well for Simulfrac, and so that is something we are incorporating into the into the program. On the wet sand side, in domestic sand in general, the only real limitation we have there is the local infrastructure. You know, domestic sand is relatively new in Canada, so the mines are just starting to ramp up. There is a lot of activity in that space. So I think, over the next year or 2, you are gonna see more domestic sand options. And then, you know, as they are putting in those sand mines, you know, we are actually allowing them to save quite a bit of capital if they do not put in a dryer and just supply wet sand. So we are working with a number of suppliers in Canada to try to make sure we get, you know, ramped up to where we can get to 100%, you know, domestic wet sand. But realistically, that is probably 28 ish kinda time frame. It will take you know, this year, we are at 50% domestic sand With a portion of that being wet. You know, next year, I would anticipate that growing, but still probably a couple years away from getting to a fully implemented program. Like we have in the Permian.
Analyst: Yeah. I appreciate that color. For my follow-up, you have 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?
Brendan Michael McCracken: Yeah. I think the opportunity still looks fairly sizable. If you think about up in the Montney when we did this 2 acquisitions, Paramount and NuVista, we had about 900 upside locations that we were gonna look to convert. We have only converted 130 of those. So and so the opportunity looks pretty good there. And then on the 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 is never gonna be completely ratable. We are gonna have to sort of work on those over periods of time, but it seems to be continuing. There does not 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 a lot of confidence we are gonna be able to maintain the inventory duration if not continue to grow it a little bit. Thanks, guys. Yep. Thanks, John.
Operator: Kevin MacCurdy with Pickering Energy Partners. Please go ahead.
Kevin MacCurdy: Hey, good morning. Apologies for kind of going back to the shareholder returns, but my question is maybe a little bit more on the mechanics of the buyback. In 2Q, your buybacks were impressive both in terms of the amount you were able to do and kind of the price you were able to execute it at. I guess maybe how did you make that decision during the quarter? And how were you able to buy back at that price, which was lower than your quarterly average? And any lessons you learned for the future?
Brendan Michael McCracken: Yeah. Maybe I can flip it over to Corey here, Kevin. talk about mechanically how we do it around blackout and-- Yeah. Kevin.
Corey Douglas Code: So as we go through it, I mean, we got our ongoing forecast, what we think our free cash flow is gonna be, and we do tailor it based on what is happening daily. To the extent we are in a blackout period, we do put in detailed instructions ahead of that just to make sure we have captured opportunities that might otherwise not be available. So when you take those 2 into account and the biggest factor here is the appreciation over the course of the quarter you know, helps the average cost compared to what we what we bought the shares back at. So, you know, it is really just a combination of being in the market regularly and then also adjusting daily if there is something going on.
Kevin MacCurdy: Appreciate it. that is it for me.
Operator: Thanks, Kevin. Phillip Jungwirth with BMO. Please go ahead.
Phillip Jungwirth: Yeah. Thanks. Good morning. I will ask another 1 on surfactants here, but just is that a $100 thousand per well, do seem to have a cost advantage versus others for utilizing this. You do have a you do a lot of data sharing. So just wondering what you think is contributing to the lower costs. And then and separately, are you looking at utilizing surfactants at all on existing base production, which has outperformed, although it sounds like it is more driven by remote operating capabilities that you mentioned.
Brendan Michael McCracken: Yeah. Hey, Phillip. Great questions. That 100 thousand per well has been part of the stacking process over the last several years and just to give you the under the hood, what we when we started the treatment costs were in that $500 thousand-a-well range that we have heard about from other operators. And with our work process here, we were doing trials in the labs to figure out what surfactants were gonna 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 the chemistries that you choose to deploy at scale in the field. So when we started at 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 cost. And that whole iterative journey has led us from that $500 thousand-a-well down to the $100 thousand-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 and a well established protocol to do that. On the base side of things, on the workover treatments, we have got a sort of a different formulation that we use on our workover side to enhance productivity that we think is yielding you know, really competitive results as well, and you see that in our updated production guide with the base being 1 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 on the workover because we think we are fundamentally solving a different physical challenge with the workovers than we are on the upfront wells. So and then final comment just to totally blow the question out. Would be that the 1 thing we have not data traded is our surfactant stuff. You know? So, you know, we have chosen to keep that 1 privilege to ourselves for now.
Phillip Jungwirth: Okay. Greg. And then most of your Montney margin comes from condensate, and there has been increasing momentum around additional egress for oil sands. How optimistic are you here? And just how supportive could that be for long term condensate fundamentals with demand pull from diluent being a positive tailwind?
Brendan Michael McCracken: Yeah. it is a really good question and quite timely. So if we wind the tape back up to January this year coming into 2026, there really was not 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 have seen just a dramatic shift in you know, just a couple of weeks ago at Stampede, it probably the big the talk of the town was how much oil sands growth was on the table in a credible way. And it is been really a combination both of those companies putting those plans together you know, kinda 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. And so if you think about it, for every million barrels a day of bitumen growth, that equates to about 300 thousand barrels a day of new condensate demand. For diluent. And so we have never seen a as strong a structural setup as we have in front of us today in Western Canada for condensate. Which is fantastic for our business. You know, it is 1 of the largest condensate producers in Canada it is a really favorable tailwind for us going forward. We will have to see how that unfolds, but our whole capital allocation and strategy in Canada for the last you know, number of years has been focused on condensate. it is the only premium hydrocarbon product in Canada, and it just looks to get more premium with time give given that backdrop. Sounds great. Thanks, guys. Yeah. Thanks, Phillip.
Operator: At this time, we have completed the question-and-answer session. Will turn the call back over to Mr. Verhaest.
Jason Verhaest: Thanks, Joanna. Thank you, everyone, for joining today. Our call is now complete.
Operator: Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect.
