Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2025 Second Quarter Results Conference Call. As a reminder, today's call is being recorded. 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 '25 conference call. This call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the beginning of our slides and in our disclosure documents filed on EDGAR and SEDAR+. Following prepared remarks, we will be available to take your questions. I 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 team delivered another quarter of strong results across our portfolio, meeting or beating all our guidance targets. Our well performance continues to be very strong. This is a combination of both our completions innovations and the consistency that comes with cube development. Our team has also continued to unlock new capital and operating cost wins. Our Montney asset integration went seamlessly as we successfully met our well cost reduction target in the second quarter, and we made significant progress on debt reduction. We are increasing our full year production guidance while cutting CapEx and OpEx while keeping our planned activity unchanged. The result is a 10% increase in our expected full year free cash flow, which means more buybacks and faster deleveraging. In our industry, there are three requirements to deliver superior durable returns. First, you need inventory depth in the best parts of the best basins. Second, you need the culture and the expertise and increasingly, the private data to convert that inventory to free cash flow. And third, you need capital discipline to make sure you're not leaking away returns by allocating capital to underperforming uses. We have centered our business around continuously improving in each of these three areas, and the outcomes of this focus differentiate us versus our peers. We believe we have assembled one of the most valuable premium inventory positions in our industry. We have focused and high-graded our asset base with anchor positions in the Permian and the Montney. And these assets are complemented by our low decline, high free cash flow generating asset in the Anadarko Basin. Our work to build inventory over the past several years means we have nearly 15 years of premium inventory in the Permian, close to 20 years of premium oil inventory in the Montney, and over a decade in the Anadarko. Our total company post-dividend breakeven price is under $40 WTI, meaning we can continue generating superior returns and free cash flow through the commodity cycle. Our team's culture and expertise has earned us a reputation as a leading operator in each of the basins we're active in. We've long been first movers in adopting innovation. And on a recent Montney tour, we unveiled how we're using AI technology to leverage our extensive private data set to optimize our execution in real time. While we showcased this in our Montney asset, we're using this new technology across our entire portfolio. This has led to faster cycle times, more production, and significant cost savings. We pioneered cube development nearly a decade ago to efficiently develop our inventory and deliver long-term repeatable results, and the benefits of this approach are evidenced by our well results, specifically in the Permian, where we're currently delivering oil type curves that have improved by 10% over the last 3 years, while most of our peers are facing productivity degradation. We remain disciplined stewards of our shareholder capital. Our focus on capital efficiency has rendered savings of about $50 million this year. We continue to execute a maintenance or stay flat program with any additional savings occurring to free cash flow. And we have complete flexibility to adjust activity should market conditions warrant. Our high-quality inventory and operational excellence are translating into highly competitive rates of return, and our capital discipline is ensuring those returns flow through to the bottom line. From 2021 to 2024, we delivered cash flow per share growth of about 25%. This growth was not driven by commodity prices. In fact, our 2024 realized price was 10% lower than in 2021. Rather, it was driven by portfolio high-grading, share buybacks, and our continued focus on profitability. And over the same period, we extended our oil inventory life by 3 years, the largest increase among our peers. In fact, most companies saw their inventory life decline. We believe our ability to continue generating superior returns will be differentiating, and we are set to deliver significant free cash flow this year, and we're confident we can continue to do this durably for many years to come. I'll now turn the call over to Corey.

Thanks, Brendan. We delivered another strong quarter, translating leading operational outperformance to our bottom line financial results. We once again beat on our production, capital, and per unit targets and improved the capital efficiency of the business. We generated cash flow per share of $3.51 and free cash flow of $392 million, both beating consensus estimates. We also returned approximately $223 million to our owners through share buybacks and our base dividend. Production during the quarter was above our guidance ranges across all products. The beat was driven by the seamless integration of our newly acquired Montney assets, a first-quarter weighted turn-in-line cadence in the Permian, and our election to shift to ethane recovery in the Anadarko. We came in below the midpoint on capital due to a combination of shifting some activity into the third quarter to better load level our program and due to continued efficiency gains. We also met or beat our guidance on all per unit cost items. Now we started the year expecting to generate about $2.1 billion of free cash flow, assuming commodity prices of $70 WTI for oil and $4 NYMEX for natural gas. At the time of our first quarter call, we revised our outlook to assume $60 WTI and $3.75 NYMEX for the rest of the year. Under this scenario and making no changes to our 2025 development program, we expected the business would still generate robust free cash flow of about $1.5 billion. Now halfway through the year and assuming the same $60 and $3.75 prices for the second half, we expect to deliver $1.65 billion of free cash flow or about a 10% improvement. This demonstrates the resiliency of our business and our drive to constantly pursue profitability. It also reinforces the value of our oil-focused development program that comes with significant torque to higher commodity prices. In addition, the savings we realize from further efficiency gains in the second half of the year will flow through to reduce capital, not higher activity, and will enhance our free cash flow even more. We are using that free cash flow to serve two important goals: reducing our debt and returning capital to our shareholders. As a reminder, our framework allocates at least 50% of post-base dividend free cash flow to our shareholders via our buyback program and 50% of the balance sheet. Since the inception of the program in the third quarter of 2021 and inclusive of our planned purchases in the third quarter of this year, we will have repurchased a total of $2.2 billion worth of shares and distributed approximately $1.2 billion in base dividend payments for total shareholder returns of more than $3.3 billion. This is roughly one-third of our current market cap. While debt reduction is a big area of focus for us in the near term, the significant free cash flow we are generating at today's prices ensures we can continue to balance both priorities. We can repurchase attractively priced shares with a 16% free cash flow yield and improve our capital structure with continued debt reduction. With just over $5.3 billion of total debt at the end of June, we expect to be below $5 billion by the end of the year. We've repaid $555 million of debt since we announced the Montney acquisition in the third quarter of last year. When you consider the acquisition added about 900 well locations, we've significantly reduced our debt, and we issued no equity; the value uplift of the transaction is hard to ignore. We continue to work towards our $4 billion net debt target. Maintaining our investment-grade credit rating remains a key priority, and we are currently investment-grade rated with a stable or positive outlook at all four rating agencies. I'll now turn the call over to Meghan Eilers, our EVP of Midstream and Marketing.

Thanks, Corey. We're excited to share several new marketing agreements that support our Montney gas diversification efforts and also complement our existing firm transportation contracts and AECO hedging efforts. As a result of these agreements, we are now less than 20% exposed to market AECO prices for the remainder of 2025 and only about one-third exposed in 2026. These agreements have added exposure to JKM pricing, increased our Chicago exposure, and enhanced our AECO netback. We have also entered into additional AECO financial hedges that include both fixed price hedges and fixed basis hedges. We have the capacity to complete similar agreements to those we executed in the quarter. And as one of the largest participants in Rockies LNG, the supplier consortium for the Ksi Lisims LNG project, we continue to explore opportunities to diversify our Montney gas exposure and to maximize profitability and returns. We are also optimistic about the potential for data centers to further enhance the margins on our gas sales and are exploring opportunities, both in Western Canada and in the U.S. We are well-positioned to participate as a supplier, thanks to our production scale and proximity to potential data centers, the depth of our natural gas inventory, and our investment-grade credit rating. We expect this will be part of our portfolio of gas sales over time. I'll now turn the call over to Greg.

Thanks, Meghan. As Brendan mentioned, we are adding volumes and cutting capital. We are reducing our full year capital spend by $50 million and increasing our oil and condensate guide by 2,000 barrels per day to average 207,000 barrels per day for the year. In addition, we've increased our annual NGL volume expectations by about 5,000 barrels per day, reflecting our expectation to recover ethane in the Anadarko for the remainder of the year. We are also reducing our guide for full year operating expense by about 3%. In the third quarter, we expect our total volumes to average approximately 615,000 BOE per day, including about 205,000 barrels per day of oil and condensate. We expect our second half natural gas volumes to be higher than the first half of the year, as the pressure we saw on gas systems in Western Canada is expected to alleviate with LNG Canada now online. Our full year gas guidance remains unchanged at about 1.85 Bcf per day. Our third quarter capital spend will come in around $550 million. Ovintiv is in an advantaged position when it comes to inventory quality and depth. We didn't get here by accident. We've deliberately taken a different development approach than most of our industry peers. The result is a 10% improvement in our Permian oil productivity per foot over the last few years, while the broader basin is fighting a 2% annual decline. Extending inventory depth and quality and maximizing resource recovery have been areas of acute focus for our teams over the past decade. Our team has done an excellent job preserving the quality and longevity of our inventory across the portfolio. We achieved this through cube development. We were early adopters of the belief that understanding how wells will interact with each other as a 4D system is critical to creating durable returns. Because of this, we take a systematic approach to resource development, where we co-develop multiple stack zones from a single well pad. This creates value by maximizing both returns and resource recovery. The temptation in developing multi-zone acreage is to cherry-pick the highest productivity wells first, then come back and drill infill wells on the rest of the acreage later. The benefit is higher initial production rates from the first batch of wells, but it comes at the expense of sterilizing large swaths of acreage because when you come back to drill the infill wells, the reservoir pressure is depleted, and the well performance of the child wells is often 30% to 40% worse than the parents. We developed the entire stack at once. As a result, we are sampling wells from across the IRR creaming curve, not just the highest return wells. We have also learned that the optimal timing to drill an adjacent cube is roughly 18 to 24 months after drilling the first. This minimizes well communication and depletion and is a dominant driver of our development schedule. The outcome is consistent and repeatable results year after year because we have not burned through our highest return inventory, and we have maximized the NPV of every acre. Nowhere is this more evident than in the Permian. Across our acreage footprint, our well productivity continues to be strong and consistent. Year-to-date performance is in line with our type curve, which is unchanged from last year. This supports durable return generation across our 12 to 15 years of premium inventory in the play. In the second quarter, we continued to see average production above our stated run rate of 120,000 barrels per day of oil. This was driven by the higher weighting of turn-in lines in the first quarter of the year. We continue to expect our rolling condensate volumes to stabilize at around 120,000 barrels per day in the back half of the year. While our cube development approach has stayed consistent, we are constantly looking for ways to drive down costs. Our team continues to push the boundaries on cycle time improvements. Year-to-date, our drilling speed averaged over 2,100 feet per day, or about 35% faster than our 2022 average. Our completion speed averaged more than 3,900 feet per day or about 50% faster than in 2022. The combination of faster cycle times with consistently strong well performance results in industry-leading capital efficiency and highly competitive returns. Now moving on to the Montney. The top priority since closing our Montney acquisition in January has been the safe, rapid, and efficient integration of the assets into our existing business, and I couldn't be more pleased with how the team has performed. Only 6 months after closing, we are already delivering $1.5 million of per well cost savings on the new acreage. $1 million of the savings has come on the drilling side, primarily from using a more efficient casing design, eliminating intermediate casing, optimizing the directional profile of the wells, and using a single bit for our lateral runs. We have taken about 10 days out of the drilling cycle time on the new assets, with a current average of less than 15 days spud to rig release. We've also achieved $300,000 of savings from using 30% less fluid in our completions designs and utilizing self-source sand. Our facilities design is saving $200,000 per well, thanks to faster build times and using 85% less structural steel than the previous operator. We've also fully integrated the acquired wells into our operations control center. This allows us to remotely operate the wells and apply the same digital workflows used in our legacy Montney operations to optimize cash flow at the individual well level. Well performance has been in line with our expectations, and we are highly confident in our ability to meet our stated Montney production run rate of about 55,000 barrels per day of oil and condensate in the second half of the year. We are optimistic about the 300 upside locations we highlighted with the announcement of the acquisition and are actively testing those areas and horizons today. Across the portfolio, we typically allocate about 10% of our D&C activity to testing upside locations, and we are taking the same approach here. I'm very proud of the team and all the efforts made to integrate the new assets into our portfolio. I'll now turn the call back to Brendan.

Thanks, Greg. I'd like to take a moment to recognize our team for the outstanding safety, operational, and financial results we've delivered year-to-date and acknowledge their focus and drive to make our business more profitable for our shareholders. Value creation in our industry will come from companies that can demonstrate durability in both their return on invested capital and the return of cash to shareholders. We are positioned to deliver on this value proposition, thanks to the depths of our premium inventory, our proven execution excellence, and our commitment to disciplined capital allocation. This concludes our prepared remarks. Joanna, we're now ready to open the line for questions.

The first question comes from Arun Jayaram at JPMorgan.

Brendan, after participating in your recent Montney tour, we left the tour thinking that OVV could be a natural consolidator of the play just given your lower D&C cost profile, lower operating costs. So I was wondering if you could just talk about your thoughts on the portfolio and if you view OVV as being a natural consolidator long-term because I know you executed your last transaction at less than $1 million per premium location, which obviously compares pretty favorably to what you see in the U.S. kind of market?

Yes, Arun, thanks for the question. Clearly, the strategy and our operating model are working. You can see that in the performance boost that we announced today. With respect to your question around the M&A piece, look, it feels really hard to beat what we've got, which establishes a really high bar as we've talked about. So we've built one of the most valuable premium inventory positions in the industry, which means we can deliver superior returns for our shareholders for a long time to come. And that focus on returns and profitability is, like I said, really showing up in the results. I appreciate your acknowledgment that we built that portfolio in a very shareholder-friendly way as it pertains to the cost of entry. As you noted, in the Montney under $1 million and in the Permian, right around $2 million a location for that most recent transaction. This means for us, if we're going to look at something, it has to be better than what we've already got, which means we're just working from a position of strength here. So we're really excited about how the integration has performed and excited about the value proposition that we showed to our shareholders with that Montney tour.

Great. My follow-up is, Corey, you reduced your cash tax guide in the U.S., I assume from tailwinds from the OVV. So wondering if you could provide some longer-term thoughts on what this could mean for your cash tax rate in the U.S., call it, over the next 3 to 5 years?

Yes, Arun, obviously, you picked up on the change to the guidance there. We took $20 million out for the year on the U.S. side. That's all from the OVV, primarily this year impact from the change to the depreciation. But looking forward, that will carry through for probably the next 3 years. The rule of thumb that we're giving people is to think about 3% of the pretax book income for the U.S. to be the run rate as we go through.

The next question comes from Neil Mehta at Goldman Sachs.

Another good quarter here, guys. I just would love your perspective on return of capital. You guys are marching towards your net debt target, and it looks like you gave a guide for Q3 around buybacks. But just your thoughts around taking advantage of the 16% free cash flow yield to the extent you're able to?

Yes, absolutely, Neil. Look, I think the value proposition is clear here. Part of the reason we've been pointing to the 25% cash flow per share growth over the last several years is to reinforce the rationale for those buybacks. And so while we maintain production at that maintenance level, we're still giving a cash flow per share growth proposition to our shareholders, which we think is very valuable and important. And so we look at this buyback through a fundamental lens. We're not trying to be procyclical with it. We're looking at what the intrinsic value of our business is at what we believe to be a conservative mid-cycle price of $55 on oil. And when we do that, we see that the shares are being priced well below that intrinsic value. We think it's the right capital allocation move to both reduce debt, which we're doing at some pace, and then also take advantage of the buyback proposition and create that cash flow per share growth trajectory for shareholders. And what I'm particularly pleased about is that we're showing we can do that through the cycle.

And then the follow-up on the Montney, which is just your thoughts around marketing. You have some new disclosures around that today, but how do you go out there and realize closer to NYMEX benchmark relative to AECO? And then just in general, what's your marketing strategy to make sure you're getting the best netbacks on this growing business?

Yes. Thanks, Neil, for highlighting that because that was an important feature to the announcement today and also to the profitability that we've been generating this year. So if you stand back from it, through the first half of 2025, we've been realizing 72% in NYMEX for our Canadian gas. That compares to AECO, which has through the same period been around 40% of NYMEX. So clearly, our diversification strategy is working. And of course, everybody is looking at the screen, you can see spot prices are even worse in AECO than that 40% today, materially worse. So this is working for us, and we've been able to add several new arrangements here. The important thing to note about these is we can't give a lot of details out. Contractually, we're obligated to keep those details confidential, but I'm going to hand it over to Meghan here in a second to kind of comment as much as we can on the specifics. I would just say these deals take some time to negotiate. They were negotiated before this latest swoon in spot prices, and they are varying terms but all sort of medium to longer term arrangements. So they really reflect the pricing more in the out years than the spot market. So Meghan, over to you on some of the details.

Yes. Thanks, Neil. Thanks so much for recognizing this. These transactions are exciting milestones that reinforce our strategy of gas price diversification. As Brendan noted, we are limited on what we can disclose. But what I can share is that the JKM deal is a physical deal with delivery at AECO. It will have us receiving a percentage of JKM for 50 MMcf a day, and that begins in 2026 and goes through 2027. Our new Chicago deal is also physical delivery at AECO. It will have us receiving Chicago less deducts on 100 MMcf a day, which is a 10-year term beginning in 2027. And our two enhanced AECO deals are physical sales contracts with delivery in BC. Those agreements are going to enhance our AECO netback on 70 MMcf a day. I mean, that's an impact now through 2027. The other thing I'd just like to point out is our JKM deal is particularly exciting as it gives Ovintiv its first exposure to LNG pricing.

The next question comes from Kalei Akamine at Bank of America.

My first question is on capital efficiency. So the updated guidance that you provided yesterday looks mainly focused on the Permian from our perspective, but I'm really curious about the Montney. Since you guys have claimed victory on the well savings, but that's an asset that you only just took over. So I have to imagine that the impact of those savings isn't fully baked into this year's program. So my question is, how many wells are you doing at the acquisition this year? How many were inherited, and how many have you designed? If the wells that you're designing are $1.5 million cheaper end to end, does that imply a more capital-efficient 2026?

Yes, Kalei, I'm going to turn it over to Greg here to run through the details. But we planned for that $1.5 million reduction in our original guidance. Really, what you're seeing is us hit that target here, which we're pleased about. Those are already baked into both the original guide and the revised guidance that we issued today. But Greg, if you want to cover the details there.

Yes. Thanks, Brendan, and thanks, Kalei, for the question. We couldn't be more pleased with how the team is executing on the integration here. As Brendan noted, the $1.5 million of capital savings was baked into our acquisition model and included in our guide. But what this means is we're now drilling and completing the wells on this new acreage with the same designs and the same cost as our legacy Montney acreage for around $525 a foot. So we've done a great job of getting that program to where we already were on our program. And so going forward, we'll keep working to reduce cost and improve efficiency. But the rate of change should be similar to what we see in our legacy programs, which is in that low single-digit improvement year-over-year. I should also point out that with the speed at which the team has been able to integrate these new capital savings, we've also connected these wells up to our operations control center. We're getting the benefit of being able to optimize them remotely. We are still on track with deferring a little capital from Q2 to Q3. We're now online to bring our first end-to-end Ovintiv designed and completed well in the Montney. That will come online in November, which is really exciting for us because it will not only use the lower cost, but we're also testing several upside zones there, and we're excited to see how those wells perform. Everything is going really well. Essentially, as we've said, the improvements have been baked into our guidance. We'll try to improve a little from here, but the big step change has already occurred.

Got it. I appreciate that. My next one is on the Permian. So in that basin, you guys are a leader in completions, and I understand that to be a water system advantage. You've got some peers that are looking at options to monetize those assets. Would you guys ever consider selling it?

Yes, Kalei, that's a great question. It's something we look at across all the different suite of ways we can create more shareholder value. I would comment that the completions cost advantage and speed advantage that we've built up is more than just the water system. It is a holistic logistics and technology approach, whether it's the real-time frac optimization that we have walked folks through a couple of times now or whether it's our local sand and then the trimal frac design. So it is an all of the above that's delivering this result, which is, I think, part of the stacked innovation strategy that we've been pursuing. As far as your question around monetizing the water infrastructure, it has a lot of value to us, probably has value in the market as well, and it's something we evaluate on an ongoing basis.

The next question comes from Phillip Jungwirth at BMO.

We've seen a lot of consolidation in the Montney, yourselves included, similar to the two big U.S. gas basins. Just wondering if there's a tipping point on consolidation where you can then say there is much greater supply discipline in the basin? And if so, how close to that do you think we are?

Yes, it's a great question. It's something we ask ourselves when we're doing our fundamentals modeling. Clearly, the Canadian market has been oversupplied on gas in the run-up to the startup of LNG Canada. As LNG Canada ramps up, that supply and demand should improve from where we are today, which is admittedly a low bar. We do ask ourselves your question around does consolidation create discipline? I think the best analog we have for that is what's happened in the Lower 48, where you can see that, that has occurred on both the oil and gas side. I think directionally, you're pointing in the right direction, and it's just sort of a matter of degree over time here.

Okay. Great. And then just sticking with the topic of Montney gas marketing. Some of your existing firm transportation agreements go to Dawn under a long-term fixed price. We still have decent term on this agreement, but just wondering how you look to position yourselves in front of this? Do you think netbacks will still be attractive at this point just because there's also the potential for more LNG startups around this time? I think you mentioned a number of other options that you're looking at on the firm transportation side beyond what you've announced today?

Yes, you bet. So just quickly on those, the kind of, let's call it, legacy downstream firm transportation, which is both West Coast, Chicago, and Dawn. All of those are long-term arrangements that we have renewal rights on, so we can effectively renew them in perpetuity, which we find quite attractive, depending on how the market evolves. The second part of your question is really about how is that market going to evolve? What we're seeing is strong demand pull in global markets for gas, which is causing more gas egress off the Gulf Coast and now off of the West Coast. More recently, we're seeing the early arrangements for demand pull on the data center side. We do see a strong fundamental gas market evolving in North America, and we think having diversified sales into multiple markets is going to let us maximize our realized price over time. Dawn is going to be one of those favored markets as those demand pulls continue to hit.

The next question comes from Doug Leggate at Wolfe Research.

Guys, I wonder if I could ask the capital efficiency question a little differently. You used to talk about $2.2 billion, I'm talking per- Permian, $2.2 billion, $2.05 billion oil and condensate. Now you're at $2.15 billion and still at $2.05 billion oil and condensate, but the efficiency is much better in the Montney, and you still haven't gotten all the way, for example, with local sand sourcing and all that kind of stuff. So I'm just curious, what's the end game here in terms of the 205,000 barrels a day, if that stays the same, where does the capital number go once you deliver all the efficiencies that you will clearly benefit from with the change in mix?

Yes, Doug, I appreciate your perspective. This situation will certainly develop over time and is not limited to our guidance for 2026. If we look back to the recent past, we were seeing figures around $2.2 billion for $200 million. The improvements in capital efficiency have been significant, and as Corey mentioned, these gains have positively impacted our shareholders in terms of free cash flow. Greg described it well; we’ve undergone another phase of integration that has brought about cost savings, enhancing our profitability and capital efficiency. Currently, everything is progressing as expected across our entire portfolio, and we anticipate low single-digit gains. We will keep monitoring this throughout the year and look forward to sharing our guidance for 2026 when the time comes.

I appreciate you taking the answers, guys. Obviously, the free cash flow yield is very different at a very different oil price. So whereas the debt reduction is permanent as always getting out. I appreciate you taking the questions. I'll take it offline.

The next question comes from Phillips Johnston at Capital One.

Just one question for me, and it's about your CapEx guidance. The implied guide for the fourth quarter suggests that the spend rate is going to fall to around $460 million or so, which is down about $75 million from the average in the second and third quarters. Just wanted to get a sense for what's driving that decrease and also get a sense of how confident you are that you can achieve that reduction?

Yes, I appreciate the question, and it's an important point to address. This is entirely performance-driven. We started the year with six rigs in the Permian, and our combined Paramount open to Montney rig count was also six. We have since reduced both to four and three, respectively. As Greg has mentioned, we've experienced faster drilling and completion throughout the year. Essentially, we're seeing a bit of a front-end loaded effect due to our increased activity performance. This capital reduction is solely based on performance, and we are pleased with the progress we've made.

The next question comes from Greg Pardy at RBC Capital Markets.

Really two very different questions. But coming back to the Montney session, I mean, data analytics, a lot of proprietary data. Just curious, how much has that been deployed either within the assets themselves? And then are there other parts of the business where you can start to deploy that learning? Or is it now pretty much fully baked?

Yes, Greg, I love the question. When it comes to this AI technology, it's obviously super nascent. I would definitely say not fully baked yet. There's a lot of running room left to go. We're just getting started, but we are deploying it across the whole portfolio. With the Montney tour, we unveiled what we're doing both in the drilling side when we took folks through our AI drill center, but on the completion side, we took people through the AI completion center, and then we took them through our production operations control room. All of these implementations are happening for our Permian and our Anadarko assets as well. So there's still much to be done. We think the technical foundation that we've laid in here, both on acquiring a unique and extensive private data set but also the culture that we've built around innovation and technology adoption in the company are reasons why our performance is going to be differentiated here.

Okay, that's helpful. I apologize to Corey in advance, but I want to return to the questions about shareholder returns. Can you remind us what your net debt target is? And what happens when you reach that level? Is it possible that you'd consider 100% buybacks? I'm curious about your thoughts on this.

Yes. So just on the target, we've talked about getting to a debt target of $4 billion, which at a mid-cycle price deck is about 1x leverage for us. We've tried to remind people this year that at current prices, we think we'll get to below $5 billion soon. That's not coming this year, but it's not that far away. As we get towards the $4 billion, obviously, there'd be more room for us to make different allocations, but we haven't committed that $4 billion is necessarily a stopping point. So not to get Doug back on the call to argue for lower debt, but again, there’s still benefit to going below that. We haven’t committed to what we’ll do past that.

The next question comes from David Deckelbaum at TD Cowen.

Brendan, I wanted to follow up on the Montney regarding a couple of things. You mentioned the steady state of activity and that you maintained your TIL target for the year at around 80 net, having achieved about half of that this quarter. Should we interpret this as more of a fluctuation related to the integration of the acquisition? Or are there some efficiency gains that may be limiting your performance, which could provide an advantage for 2026?

Yes. The higher 2Q TIL in the Montney was really off of the integration. We took over those Paramount assets in January. There was a tail of higher activity. This was the combined 5 rigs moving to 3. So it was really just absorbing those wells and completing them quickly. That's why that higher run rate in 2Q. I think the guidance profile will settle in through the rest of the year here, and we'll finish out with that around 80 TILs in the play.

Appreciate that. And perhaps just following up a bit, just you talked about obviously getting to that $1.5 million of savings being baked in. I know expectations are perhaps that continues to improve as you guys kind of do the full suite of completion on your side. But I guess as we're thinking about the broader portfolio, you trend CapEx in the Permian and the Anadarko on mostly efficiencies. Where we stand today? Do service costs present sort of a tailwind going into the '26 program at this point? It seems like a lot of the gains we've seen so far are more timing-oriented.

Yes, David, I appreciate that question to surface that on the pricing side. So yes, what we're seeing in '25 is service cost deflation kind of matching our expectations. When we came into the year, we thought we'd see something in the low- to mid-single-digit service cost deflation, and that's what's materialized. By category, there's some variance, of course. But net-net, that's what we're seeing. So really inflation, deflation is not a feature of our guidance update today; that's a true efficiency gain. As we look towards '26, as you're asking, that's really kind of still a jump ball. We're seeing activity levels drop across North America, which is putting some pressure on service pricing. So that's a place where we're sitting here today, probably optimistic on some deflation in '26, but let's let that play out, and we'll integrate that into our '26 guidance. But directionally, that's where it's headed.

The next question comes from Geoff Jay at Daniel Energy Partners.

I was wondering if you could explain how the combination of cube development and your reoccupation strategy affects your reinvestment rate over the long term compared to a more traditional development approach.

Yes. I think what it's going to do is mean our reinvestment rate can continue where it's at and get better as we incorporate efficiencies, whereas the traditional approach, if you're not sort of taking the cube development approach, tends to lead to step changes as inventory degrades in quality. What we're insulating our investors with is sampling the remaining premium inventory that we have with every annual program, which is going to lead to a very durable return on invested capital and free cash generation at constant prices over a long period of time. So we think that's the right way to be disciplined with our capital allocation, but also going to be a real differentiated advantage for our investors in a maturing play type like shale is today.

Excellent. And then maybe just a follow-up on Greg Pardy's question a little bit. I definitely got the sense on the Montney tour that maybe some of the tech innovations, remote monitoring, etc. were maybe not as fully deployed in the Lower 48. Is that not true? I just wonder if there's more to come in terms of if there's more stuff to do in the Lower 48 than there is in the Montney at the moment?

Yes, I think all of this stuff is like less than a year into deployment, so it's still very much in the ramp-up phase. Greg probably has some specific comments to add on the uniformity across the portfolio.

Yes. I think what I'd add is that on the drilling and completion side, the idea that it's still very much emerging, I would agree with. Probably what you're noticing from the tour is the operations control center that we've been employing up in Canada; we've been doing that for about a decade. That's a really legacy competency we've been building on over time. We're building that same competency in the U.S. and maybe that's a little bit behind. But the goal going forward is to employ all of those latest, greatest workflows across all of the portfolio. We're kind of at the same place on D&C across all three assets. On the production optimization side, we might be a little bit ahead there in Canada, but working to get them all caught up.

The next question comes from Josh Silverstein at UBS.

Just wanted to walk through the Permian turn-in line cadence for the year. You guys have clearly gotten off to a pretty good start there and are still looking at kind of 135 wells for the quarter. Just kind of walk through that because the production numbers for the first half were definitely stronger than expected.

Yes, I'll just flip it to Greg there. Thanks, Josh.

Yes. So just as a reminder, the original plan was to have more activity there in the first half of the year in the Permian. We had some DUCs that we had built up due to running 6 rigs and then 5 rigs last year. We're now down to 4 rigs. We had planned on having a little more activity in the first part of the year. The team actually even did a little better than we expected, completing our wells a little faster, which brought even a few more wells into the first half. This allowed us to shift some completion spend from Q2 out into Q3 just to spread out the activity, have a little more load-level program in the back half of the year. We're not changing the turn-in line count for the full year. Keep in mind, sometimes these shifts are within quarters. So we're bringing on wells in the first part of the quarter versus the back part of the quarter that may not show up on a turn-in line count but will show up in production. But overall, the plan is just to have a load-level program in the back half of the year in the Permian and the Montney. That's our plan.

Got it. And then just coming off the Montney tour as well, obviously, a lot of focus on the D&C cost reduction that you guys are doing up there at the $1.5 million level. Can you just talk about what you guys can do just on the OpEx side as well and then maybe some of the impacts of being a little bit more condensate focused versus gas-focused up there? It seems like there's still ways for you guys to chip away at that, maybe some goals there.

Yes, Josh. That's great. I'm glad you highlighted that. I think when you stand back and you look at the collective batch of enhancements we made to our '25 plan here, the sum total is $150 million worth of free cash flow and LOE reduction is one of the pieces that drove that. A couple of things specific to the Montney, one of the other features helping us is our operating capability on the new assets has led to higher run times. Of course, the work we've been doing with our midstream providers is leading to higher run times at their facilities, which flows through to ours as well. All of that is a boost to per unit OpEx because you're just being more effective with the dollars you're spending. But Greg, I don't know if you want to comment on anything more specific?

Yes, I think the other opportunity we have is using our operations control center and some of our machine learning and AI tools that allow us to optimize gas lift. Just further increases our ability to keep those wells online and optimized up in Canada and across the portfolio. One other thing that's really helping with the downtime is well disruptions are less frequent, and we're seeing better run times. When we do have disruptions now that we have automation fully deployed across the new assets, we can return production much faster when an offset does occur. All of those things lead to better production for the same or lower cost, which will have some downward pressure on LOE going forward.

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

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

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