Ovintiv Inc.(OVV)Q2 2026 法說會逐字稿

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2026 Second Quarter Results Conference Call. As a reminder, today's call is being recorded. 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 Ovintiv representatives. However, members of the media who wish to quote others who are speaking on this call today are advised 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.

Thanks, Joanna, and welcome, everyone, to our second quarter 2026 conference call. This call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the beginning of our slides and our disclosure documents filed on EDGAR and SEDAR. Following prepared remarks, we will be available to take your questions. I will now turn the call over to our President and CEO, Brendan McCracken.

Thanks, Jason. Good morning, everybody, and thank you for joining us. Our second quarter results demonstrate the strength of our durable return strategy and the business we have built. Our future is also looking bright with a boost to our oil production, driving more free cash flow, differentiated cost and productivity results, the demonstrated ability to replace our inventory, and ramping buybacks. We have demonstrated industry-leading operational performance through stacked innovation and execution excellence. Our culture, our expertise, and our unique private 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 one of the most innovative, efficient, opportunity-rich E&Ps in North America, and we are very excited to be operating from this position of strength. Both our Permian and our Montney year-to-date results are tracking above type curve and continue to lead the league in their respective basins. This is driving an increase to our full-year oil production guidance, which equates to about 4% growth on a per-share basis with no additional capital or activity. Our cash flow per share and free cash flow both beat consensus estimates by a significant margin this quarter, and we returned approximately 63% of free cash flow to our owners through share buybacks and our base dividend. Our net debt was below $3 billion at the end of the quarter, marking the lowest leverage the company has had in over a decade. Our capital structure has been 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 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 10,000-foot location, and we did it without diluting our shareholders or stressing our balance sheet. Our work to build inventory depth means that we have nearly 15 years of premium inventory in the Permian and close to 20 years of premium oil inventory in the Montney. This expansion has been unmatched by our peers. In fact, over the same time period, most companies saw their inventory life decline. Our goal now is to maintain our premium inventory 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 in order to maximize the returns and value we generate from every acre of resource we develop. We have deliberately built a culture of relentless curiosity that seeks to create our own innovations but equally 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, and our private data combined together are hard to do and 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 have 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 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 one 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 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 dataset, optimize our technical workflows, and optimize 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.

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 came in at 615 thousand BOE 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 BBB from BBB-. Our team is continually focused on improving our capital efficiency and our outstanding operational performance through the first half of the year gives us confidence in what we can achieve through the second half. We 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 outperformance from our base. We are raising the Permian's go-forward run rate to 125 thousand barrels per day and our full-year total company oil and condensate production guidance to 210 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 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 2026 capital program, outside of higher diesel costs. We expect to offset any additional cost inflation with operational efficiencies. As such, our full-year capital guidance remains unchanged. In the third quarter, we expect production to average approximately 628 thousand BOE per day, including about 208 thousand barrels per day of oil and 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.

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 a 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 prices 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 non-surfactant-treated well. We think surfactants account for roughly half of the 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 to 85 thousand barrels per day. Also of note was our Montney gas price realization at 187% of AECO. Our diversified portfolio of both physical sales out of the basin and financial arrangements to price our gas away from AECO continues to be highly valuable. Uniquely this quarter, our realized gas price was boosted by sulfur revenue. Sulfur is a byproduct of our gas production in certain areas across our Montney acreage. Typically, it is an expense to extract this product from our gas stream and transport it to the West Coast market. In the second quarter, however, sulfur prices were historically high and contributed about $40 million in revenue. While it 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 4,900 feet per day, or about 20% faster than our 2023 performance and about 40% faster than the current pace of our Montney peers. We recently established a pacesetter of more than 7,000 feet of completed lateral length per day using 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 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 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 Hub-to-Benson 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, 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.

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.

Thank you. Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing star 1. 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 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. 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 you are most excited about, and what is the sustainability of the advantage? Because the old adage 'there are no secrets in the Permian' has some truth to it.

Hey, Neil. Thanks for the question. I appreciate the interest here. First thing I would say is the surfactants have obviously been a big piece. We have been pegging it at about a 9% uplift on our type curve, so obviously really important but far from the whole story. That is why we have 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 cracks with about 70 different input criteria that we select to deliver the maximum recovery, all the way through to surfactants. 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 and through our active data trading strategy to accumulate the ability to define causality. Defining those causal relationships is what's really valuable in the subsurface, particularly on productivity and recovery. If you think about your point on 'there are no trade secrets or intellectual property in the Permian,' I think that is true of the industry overall. We get on calls like this and talk about the recipes. So really, where the moat comes from is the whole system here. That is why we have taken some pains to describe it as starting with the culture—the 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 we have built that into our culture. It obviously comes from the expertise side where we have created institutional capability to execute at the leading edge. 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, while the headlines are available, the details of how to do that as a company at scale are really hard to mimic and duplicate. And then the final thing is the private data, where we have assembled a very large, we believe unique, private dataset across both the Montney and the Permian that allows us to establish those causal relationships with confidence and then incorporate them into our designs at scale. So yeah, I think that answers your question.

That is really impressive. 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 foreign domicile eligibility criteria. Can you just take us into any conversations you are having or how you are thinking about that potential as that could change the shareholder base and be a catalyst for the story?

Yeah, Neil. Great point. There is some news this week on that front. S&P has begun a formal comment period that they kicked off earlier this week. That comment period is open until August 21 on the potential inclusion changes for the TSX indexes. They have indicated that following that comment period, they would look to make any changes to inclusion ahead of their September rebalancing, which would be a September 18 event. In that comment process, they specifically called out Ovintiv as one of three companies that would meet the proposed criteria for eligibility to be included in the TSX. So that is all news and constructive. We will have to wait and see for that comment period to conclude and see what their final decisions are. If you take their proposed methodology, which would have a 50% weighting for companies like Ovintiv, that would imply—based on analysis we have seen in the last 24 hours from several banks—that there could be anywhere from 3 to 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 active managers that would now be benchmarked to that index. All of this is constructive for us, and I think comes at a great time for us as well because there is a lot of interest from Canadian investors and at least a couple of Montney players that are going away through transactions. So definitely a tailwind for us. We will wait and see how it all shakes out during the comment period. Thanks, Neil.

Greg Pardy with RBC Capital Markets. Please go ahead.

Hey, thanks. Good morning. I wanted to build on what Neil was asking about. How much of the difference is there in terms of the implementation of surfactants in the Permian versus the Montney? And at what stage have you begun to implement it in the Montney, or is it very early stages there?

Great question, Greg. We are at very early stages in the Montney. We have been relatively advanced in the Permian; this year almost every well is going to have a surfactant treatment. In the Montney, we are just getting started. The lab results are very encouraging. If you think about the four to five years of cycle time we had in the Permian to validate and scale it, we will be able to accelerate that in the Montney. So I do not think it is imminent to have a final conclusion on efficacy in the Montney, but we will be able to accelerate relative to the pathway we took in the Permian. We are building on that knowledge and applying it up north, which is exciting.

Okay. Thanks for that. I am also trying to reconcile shareholder returns, the balance sheet, and dividends. You are in an awfully good place now with net debt really reduced. What do you think about an optimal capital structure? You said you are about 45% in shareholder returns year-to-date and you are targeting 60% for the full year. Given the discount to intrinsic value, do we see a big emphasis on buybacks in the back half of the year, or do you still think there is room for net debt reduction?

I think you painted it well, Greg. We do not have a crystal ball on commodity prices, so we are mindful of that. At the same time, we see a big intrinsic value gap in the shares and see a lot of value in buying shares back, which is why we are signaling greater than 60% for full-year returns. From a capital structure perspective, we feel really good about what we have created. We have lots of free cash flow to enable the combination of buybacks and further debt reduction. The ground game can also be funded out of that free cash flow. You should expect that ground game to be modest-sized deals—we have line of sight in both the Permian and the Montney to do bolt-on deals at very attractive entry points. Think of that ground game being in the low hundreds of millions of dollars range. So we are taking a balanced approach—buybacks, some debt reduction, and modest bolt-on activity funded from free cash flow.

Neal Dingmann with William Blair. Please go ahead.

Thanks for the time. Good morning, Brendan. My first question is around your stacked innovation approach. Specifically, have you applied this approach fully or started applying it to the Montney? If not fully applied yet, do you plan to do so in the coming quarters?

We are early days and excited about applying the stack more broadly. I will turn it over to Gregory to provide color on where we are with specific technologies.

Appreciate the question, Neal. If you think about the stacks on slide 8, each one is the culmination of years of work. Things like cube development, spacing, and stacking we have been doing in both plays for a decade. But things like Simulfrac and wet sand have had different levels of application in each play. We continue to improve how we do that in the Permian and are a little earlier in the process in the Montney. As we reported, our first full wet sand trial in the Montney this quarter went very well. We think we will lean into that more throughout this year and into next. It will take time for the infrastructure to catch up. The technology I am most excited about is AI—the new digital tools we have been building on both sides of the border to help not only on drilling and completion efficiencies, but also on base production. Different places in each asset and on the stack, but we are applying it across the board and there is still room to go.

Makes sense. My second question is about Montney G&P and transportation costs. Now that you have a massive position after adding NuVista and Paramount, what is the potential to reduce G&P and transportation costs? What opportunities do you see to drive savings?

Great question. The majority of our G&P exposure is in Canada in the Montney. We are just getting going with combining the legacy, Paramount, and NuVista positions. When we did those deals, we signaled there would be tangible synergies and those are being incorporated into the business. This is a longer-term opportunity to find more profitability by combining those positions together, and G&P is a big bucket. We expect this to unfold over time—multiyear—not overnight. We do not have specific guidance baked into this year, but we are very focused on this as an opportunity to drive free cash flow growth going forward.

Arun Jayaram with JPMorgan. Please go ahead.

Good morning, team. Brendan and Corey, you raised your second-half Permian crude and condensate guidance to a 125 thousand barrels per day run rate versus previous messaging around 120 as the run rate. Should we perceive this as the go-forward maintained production rate in the Permian? Could you expand on that?

I will let Gregory take this one as it is really his team that delivered it, Arun.

Thanks, Arun. Yes, we are saying 125 is the run rate go-forward in the asset—not just the rest of this year but beyond. This assumes a level-loaded program in the Permian, so we are not adding more activity or capital. Over the last several quarters we have seen exceptional results in the northern Midland Basin and that performance has persisted across the portfolio. We are seeing strong results from new wells and from base production. The base performance improvement comes from our Operations Control Center in Midland where we use AI and automation to optimize ESP parameters, reduce downtime, flatten declines, and improve run times from artificial lift. We brought monitoring and optimization in-house for rod pumps and built tools to get wells back online quicker when failures happen. All of that reduces zero days and shallows declines, improving the base. The combination of new well performance and base performance gives us confidence in the 125 run rate going forward.

Thanks, Greg. Quick follow-up on Montney well productivity in 2026: what are the drivers there? It sounds like surfactants are not the main driver yet—are we seeing a mix of new properties, density increases at Karr and Wapiti, or other contributions?

We have seen really strong results across the entire position. Strong performance in legacy areas like Dawson, good pads in Pipestone, and newer areas like Karr and Wapiti. The results are a combination of stage architecture work, proppant intensity, and other stack innovations we applied in the Permian and are applying in the Montney. We leaned in on density a bit on newer properties in Wapiti and Karr; density tests performed as expected in most cases and some deeper zones in Sexsmith are doing even better. We are pleased with results across Canada and expect that to continue.

Douglas Leggate with Wolfe Research. Please go ahead.

Hello. Good morning, guys. I have two questions. First, on proppant and wet sand and the impact on decline curves: that implies capital efficiency is improving and sustaining capital could decline unless you take the higher production. Do you maintain activity and let production rise, or do you maintain production and reduce spending? Second, on cash returns: you have materially delevered and you are buying back shares. Why not use the windfall to further reduce net debt?

Great question. Historically, we've done a bit of both. When commodity prices are elevated like today, growing volumes and creating more free cash flow makes sense—that's what you have seen us do. In periods of lower prices, we've pocketed capital savings and created more free cash. Today, it makes sense to hold activity flat and let the benefits accrue to volume growth and free cash flow, which is what you see in the announced 4% per-share bump. Regarding net debt versus buybacks: we do not have a crystal ball on commodity prices, so we take a prudent, balanced approach. We have reduced a lot of debt already—the quarter's results show $3.4 billion of debt reduction. We believe in running the business at low leverage and we are pleased with where we are. Our approach is to balance buybacks, some debt paydown, and continued investment in attractive bolt-ons when they meet our criteria.

Thanks. I will take it offline.

Gabe Daoud with Truist. Please go ahead.

Thanks. Maybe a question for Gregory. Any updated thoughts on the Barnett position? You disclosed a 100 thousand acre position held by production. What are the plans there? I believe you planned to drill a well this year—any update?

I will pass that to Gregory, but one quick point: the Barnett acreage we disclosed last quarter is all on existing acreage. This was not an external transaction; these are acres we have held in the play for a decade plus. It is a great opportunity to work into the play while learning from others. Gregory, you can talk about the well.

Thanks, Gabe. The industry is learning a lot about the Barnett right now with a lot of activity and data from peers operating around our position, which gives us encouragement. These are held acres, so we do not have to drill aggressively today. We have started drilling our first well: we have drilled and cored the vertical section and the core looks very encouraging. This is a well in Martin County; we are proceeding with drilling the lateral and expect that well to come online late this year. It will give us information on productivity, well cost, and drilling efficiency. It also gives us trade currency—we can share core and well data with peers to learn more. We are participating in small working interests with some peer wells. Generally, we will watch others delineate product windows in the play and learn what costs look like. I would not envision a large ramp-up next year—maybe a well or two—while we continue to optimize our position and learn.

Thanks, Greg, and thanks, Brendan, for clarifying. My second question: following the Pembina-Métis announcement a few weeks ago, any update on your efforts on the data center front—are you seeing opportunities to place gas into data centers?

Thanks, Gabe. We are encouraged by market development for data centers in Western Canada. Our strategy is to diversify gas sales away from AECO, and data center build-out is another outlet we are excited about. We expect it to be a place to put some of our gas over time, along with growing LNG capacity off the West Coast. All of this is constructive for our ability to diversify gas away from AECO, and Gregory and Corey highlighted benefits we already see in our realized gas prices.

Scott Gruber with Citigroup. Please go ahead.

Good morning. I want to come back to balancing cash returns and the balance sheet. Some peers have delevered and discussed using the balance sheet during industry sell-offs to juice buybacks. Is that something you would contemplate over time with a healthy balance sheet? Would you think about positioning the balance sheet for that?

Good question, Scott. It is something we will be thoughtful about. We are new to this stronger balance sheet position, but having just arrived here, those are the types of scenarios we are considering. I would not take that off the table. It is down the road relative to current commodity prices, but it could be an option depending on circumstances. Our overall orientation remains value-focused—where do we see the best return on capital?

Makes sense. On CapEx, you highlighted your diesel displacement strategy. You utilize electric frac in the Permian. What other steps are you taking to reduce diesel consumption across the D&C spend?

I will let Greg take that one.

Thanks. In addition to electric frac fleets in the Permian, we have a natural-gas-fired frac fleet operating in Canada, which displaces diesel there. Many of our drilling rigs are dual-fuel and can operate on natural gas as well as diesel, so we are ramping up natural gas usage. We are also eliminating diesel-fired generation in the field where we can and getting on grid power. Our wet sand mines reduce trucking and therefore diesel pass-through costs. So it is across the portfolio—less diesel usage, fewer pass-through inflation impacts, and we offset any diesel inflation with operational efficiencies. That has been successful year-to-date and we expect to continue.

I appreciate the color. Thank you.

Christopher Baker with Evercore ISI. Please go ahead.

Hey, guys. Thanks for the time. Brendan, earlier you talked about a dynamic macro environment. How are you and the team thinking about the 2027 growth option the portfolio provides?

Great question. The first thing to note is the growth with no capital or activity—our 4% per-share growth with current programs is the first thing to consider as we think about 2027. We continue to evaluate when it would be right to invest for growth, but it is premature to say for 2027. We'll watch global fundamentals—Gulf developments and where Chinese demand normalizes are important factors. Our orientation remains value-driven: if growth provides the best return on invested capital, we will pursue it. We have inventory and logistics to support growth in both assets, but we will weigh that against buybacks, which look very attractive on a per-share basis today.

Thanks. Follow-up: on the Permian higher plateau, the type curve in the slides is pretty much unchanged. If continued outperformance persists, could revisiting the type curve represent upside to the guide? How should we think about revisiting the type curve?

We continually study the data and look for ways to improve type curves, but for now the guide makes sense for modeling the company. We are always open to improvements as more data accumulates through the rest of this year and into next, but the current guidance is what we believe is appropriate today. Boosting guidance to the 125 run rate was a value-accretive move for shareholders.

John Johnston with Texas Capital. Please go ahead.

Good morning. My first question: the pacesetter Simulfrac operation achieved completion speeds of over 7,000 feet per day, and domestic wet sand reduced sand cost by 20%. How repeatable are these results and what percentage of the Montney program could ultimately adopt each technology and over what time frame?

John, I will pass this to Gregory. Historically, we think of pacesetters as targets to convert into averages—show once, then make it repeatable.

For Simulfrac, the main limitation is pad setup and logistics, and almost all of our Montney operations are set up well for Simulfrac, so we are incorporating it into the program. On domestic wet sand, the limitation is local infrastructure—domestic sand is relatively new in Canada and mines are ramping up. Over the next year or two, you will see more domestic sand options. In Canada, supplying wet sand eliminates the need for drying, which saves capital for suppliers and helps accelerate adoption. This year we are at about 50% domestic sand with a portion wet; next year we anticipate growth, but getting to fully implemented programs like the Permian will take a couple years.

Thanks. Follow-up: you 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? Should we expect organic additions to continue offsetting annual drilling activity over the next several years?

The opportunity still looks sizable. In the Montney, when we did the Paramount and NuVista acquisitions, we had about 900 upside locations; we have only converted about 130 of those so far, so the opportunity remains. In the Permian, the recent Barnett opportunity is another example and we continue to evaluate all horizons on our acreage to convert upside into premium inventory. It won't be perfectly ratable, but the cadence continues and combined with small bolt-on deals at attractive entry points, we are confident we can maintain or grow inventory duration.

Kevin MacCurdy with Pickering Energy Partners. Please go ahead.

Hey, good morning. Apologies for circling back to shareholder returns. In 2Q your buybacks were impressive in both amount and execution price. How did you make that decision during the quarter and how were you able to buy back at a price lower than your quarterly average? Any lessons for the future?

I will let Corey talk about the mechanics.

We maintain an ongoing forecast of expected free cash flow and tailor our activity based on daily market developments. If we are in a blackout period, we put detailed instructions in place ahead of time to capture opportunities that might otherwise be missed. The biggest factor in achieving a lower average cost is appreciation over the course of the quarter combined with being in the market regularly and adjusting daily when opportunities arise.

Appreciate it. That's it for me.

Phillip Jungwirth with BMO. Please go ahead.

Thanks. A quick question on surfactants: you mentioned $100 thousand per well for custom treatments that have driven uplift. How have you achieved that cost advantage relative to others? Also, are you looking at utilizing surfactants on existing base production workovers?

Great questions. When we started, treatment costs were in the $500 thousand per well range reported in the industry. We conducted lab trials to find chemistries with the right efficacy in the field—some chemistries actually reduce productivity, so lab work matters. We trialed the better chemistries in the field, proved them up, and then iteratively worked on substitutes in the lab to lower costs while maintaining efficacy. That iterative journey brought costs down from around $500 thousand per well to about $100 thousand per well. It takes time and a well-established protocol to do that. On the base/workover side, we use a different formulation tailored for workover treatments to enhance productivity and we see competitive results there as well. So it is not necessarily the exact same surfactant as the upfront treatment, but a different formulation for a different physical challenge. One additional note: we have not data-traded our surfactant work broadly, so we have kept some of that proprietary.

Thanks. One more on condensate: most of your Montney margin comes from condensate and there has been increasing momentum around oil sands expansion and additional egress. How optimistic are you and how supportive could that be for long-term condensate fundamentals given diluent demand?

It is a timely question. As of January this year, there weren't many credible new oil sands growth projects. Since then, there has been a dramatic shift—companies have put plans together and there has been policy support from federal and provincial governments to enable egress for bitumen. There now appears to be a quite credible list of shovel-ready oil sands growth projects. For every million barrels per day of bitumen growth, that equates to about 300 thousand barrels per day of new condensate demand for diluent. We have not seen as strong a structural setup for condensate in Western Canada as we see today, which is a favorable tailwind for our business. Condensate is a premium hydrocarbon product in Canada and it looks set to remain premium given these demand drivers.

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

Thanks, Joanna. Thank you, everyone, for joining 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.