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DATE
Friday, July 25, 2025 at 2:00 p.m. ET
CALL PARTICIPANTS
President and Chief Executive Officer — Brendan McCracken
Executive Vice President and Chief Financial Officer — Corey Code
Executive Vice President, Midstream and Marketing — Megan Eilers
Executive Vice President and Chief Operating Officer — Greg Givens
Vice President, Investor Relations — Jason Verhaest
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TAKEAWAYS
Free cash flow: Free cash flow (non-GAAP) was $392 million in Q2 2025. Full-year 2025 free cash flow guidance was raised by 10% to $1.65 billion (non-GAAP), assuming $60 WTI and $3.75 NYMEX for the second half of 2025.
Cash flow per share: Cash flow per share (non-GAAP) was $3.51 in Q2 2025, surpassing consensus estimates.
Shareholder returns: $223 million was returned through buybacks and the base dividend in Q2 2025. Cumulative total shareholder returns since Q3 2021 exceed $3.3 billion, representing about one-third of current market cap as of Q2 2025.
Debt reduction: $555 million has been repaid since the Montney acquisition as of Q2 2025. Total debt as of June 2025 stood at just over $5.3 billion. Management expects total debt to fall below $5 billion by the end of 2025.
Capital expenditure: Full-year 2025 CapEx was reduced by $50 million. Q3 2025 CapEx is projected to be around $550 million. Targeted Q4 2025 spend is expected to fall to approximately $460 million, the lowest of the year.
Operating expense: Full-year 2025 OpEx guidance was reduced by about 3%, reflecting efficiency gains and higher facility run-times.
Production guidance: Oil and condensate guidance was raised by 2,000 barrels/day to 207,000 barrels/day for the full year 2025. NGL guidance was increased by 5,000 barrels/day for the full year 2025. Full-year 2025 natural gas guidance remains at 1.85 Bcf/day.
Permian productivity: Oil type curves in the Permian have improved 10% over the last three years. Per-foot productivity in the Permian has increased 10% over the last few years, versus a basin-wide 2% annual decline. Cycle times have improved, with drilling 35% and completions 50% faster than in 2022 (year-to-date 2025).
Montney integration: $1.5 million per well in cost savings was achieved on newly acquired Montney acreage as of Q2 2025. Well costs are now at approximately $525/foot per new well as of Q2 2025, in line with legacy Montney. 900 well locations were added from the Montney acquisition, with 300 upside locations under testing following the Montney acquisition in January 2025.
Gas price diversification: New agreements have reduced 2025 AECO price exposure to less than 20% for the remainder of the year and 2026 exposure to about one-third. New long-term JKM- and Chicago-linked deals have been secured, with the JKM deal beginning in 2026 and running through 2027, and the Chicago deal beginning in 2027 with a ten-year term, marking the company's first LNG price exposure.
AI and digital tools: Remote operations and digital workflows are now fully integrated in Montney and are being expanded to US assets. Improvements are expected to increase efficiency and lower costs portfolio-wide.
Buyback policy: At least 50% of post-base dividend free cash flow has been allocated to shareholders via the buyback program, with the remainder to debt reduction, maintained since Q3 2021.
Inventory depth: 12-15 years of premium inventory in the Permian, close to 20 years of premium oil inventory in the Montney, and over 10 years of premium inventory in the Anadarko. Oil inventory life extended by three years from 2021 to 2024.
Breakeven price: The total company post-dividend breakeven price is under $40 WTI, enabling free cash flow resiliency across cycles.
Cash tax rate guidance: US cash tax was reduced by $20 million for the year due to OBB. A 3% pretax book income run rate is projected for the US over the next three years.
SUMMARY
Ovintiv(OVV -0.15%) management lowered capital and operating expense forecasts, citing durable efficiency gains and robust asset performance. Long-term gas marketing diversification materially limits AECO exposure through 2026, with less than 20% exposure for the remainder of 2025 and about one-third in 2026, with new JKM and Chicago-linked contracts signed for physically-delivered sales. The Montney acquisition delivered immediate cost reductions and operational control integration, with 900 new locations from the Montney acquisition and approximately 300 upside targets now in testing as of Q2 2025. AI-driven remote operations and process automation are expanding from Canada to US assets, designed to further accelerate cost-competitive execution. Strategic capital allocation—split between buybacks and deleveraging—and a post-dividend breakeven price under $40 WTI position the company to sustain free cash flow and returns across commodity cycles.
Chief Executive Officer McCracken said, "our 2024 realized price was 10% lower than in 2021," yet cash flow per share grew by about 25% from 2021 to 2024, attributed by management to portfolio high grading, share buybacks, and efficiency focus.
Exposure to volatile AECO benchmark is now under 20% in 2025 and about one-third in 2026, through new physical and financial hedge transactions combined with additional firm transportation and marketing agreements.
Cumulative shareholder returns since share repurchase initiation in Q3 2021 represent roughly one-third of current market capitalization, highlighting the capital return emphasis.
Chief Financial Officer Code stated the net debt target remains $4 billion—equivalent to approximately 1x leverage at mid-cycle pricing—though management signals potential for further reduction beyond that level.
Integration of proprietary AI analytics and digital operations centers is described as "early days," with the company committed to deploying unified workflows portfolio-wide for additional operating leverage.
INDUSTRY GLOSSARY
Cube development: A drilling and completion methodology where multiple stacked reservoir targets are codeveloped from a single pad to maximize resource recovery and minimize well interference and depletion risk.
TIL (Turn In Line): A measure of newly completed wells brought into production during a specific period.
DUC (Drilled but Uncompleted Well): Wells that have been drilled but have not yet undergone completion operations, thus not yet producing hydrocarbons.
JKM (Japan Korea Marker): A leading benchmark price for liquefied natural gas (LNG) delivered to North Asia.
AECO: The Alberta Energy Company natural gas price index, a key Canadian gas benchmark known for historical volatility.
Netback: The realized revenue per unit of production after deducting transportation, processing, and other costs, reflecting actual profitability per produced unit.
Full Conference Call Transcript
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've 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 inventories 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, the Anadarko Basin. Our work to build inventory over the past several years means we have nearly fifteen years of premium inventory in the Permian, close to twenty 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 continue generating superior returns and free cash flow through commodity cycles.
Our team's culture and expertise have earned us a reputation of being a leading operator in each of the basins we're active in. We've long been first movers in adopting innovation, and on our recent Montney tour, we unveiled how we're using AI technology to leverage our extensive private dataset to optimize our execution in real-time. While we showcase 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.
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 10% over the last three 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. Over the same period, we extended our oil inventory life by three 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.
Corey Code: 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, which comes with significant torque to higher commodity prices.
Any additional savings we realize from further efficiency gains in the second half of the year will flow through to reduced 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% to 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 a 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 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 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 Megan Eilers, our EVP of midstream and marketing.
Megan Eilers: Thanks, Corey. We're excited to share several new 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 a third exposed in 2026. These agreements have added exposure to JKM pricing, increased our Chicago exposure, and have 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 Thylisms 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 US. 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.
Greg Givens: Thanks, Megan. As Brendan mentioned, we are adding volumes and cutting capital. We are reducing our full-year capital spend by $50 million, 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 1.85 Bcf per day. Our third-quarter capital spend will come in around $550 million. Ovintiv Inc. 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 across the portfolio. We achieve this through cube development. We were early adopters of the belief that understanding how wells will interact with each other as a four d system is critical to creating durable returns. Because of this, we take a systematic approach to resource development, where we codevelop multiple stacked 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 develop 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've also learned that the optimal timing to drill an adjacent is roughly eighteen to twenty-four 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. 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 twelve to fifteen 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 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 cost. 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 six 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've taken about ten days out of the drilling cycle time on the new assets, with a current average of less than fifteen 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 DNC activity to testing site 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.
Brendan McCracken: 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 their 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.
Operator: Thank you. First question comes from Arun Jayaram at JPMorgan. Please go ahead.
Arun Jayaram: Yes. Good morning, Brendan and team. Brendan, after participating in your recent Montney tour, you know, we left the tour thinking that Ovintiv Inc. could be a natural consolidator of the play just given your lower D and C cost profile, lower operating costs. So I was wondering if you could just talk about the portfolio thoughts on the portfolio and if you view Ovintiv Inc. as being kind of a natural consolidator longer term because I know you executed your last transaction at, I think, less than a million dollars per premium location, which obviously compares pretty favorably to what you see in the US market.
Brendan McCracken: Yeah, Arun. Yep. For the question. But 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, this feels really hard to beat what we've got, which establishes, you know, as we've talked about, a really high bar. 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.
You know, 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, as the Montney under a million, in the Permian right around $2 million a location for that most recent transaction. So this means for us, you know, we're gonna 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 I'm really excited about how the integration has performed and excited about the value proposition that we showed our shareholders with that Montney tour.
Arun Jayaram: Great. My follow-up is Corey, you reduced your cash tax guide in the US. I assume from tailwinds from the OBBB. Wondering if you could provide some longer-term thoughts on what this could mean to your cash tax rate in the US, call it over the next, you know, three to five years?
Corey Code: Yeah. Arun, obviously, you picked up on the change to the guidance there. So we took $20 million out for the year on the US side. That's all from the OBB primarily this year impact from the change to the depreciation. But looking forward, that'll carry through for probably the next three years. Kind of the rule of thumb that we're giving people is to think about 3% of the pretax book income for the US to be the run rate as we go through.
Arun Jayaram: Great. Thanks a lot.
Operator: Thank you. The next question comes from Neil Mehta at Goldman Sachs. Please go ahead.
Neil Mehta: Another good quarter here, guys. It just would love your perspective on return of capital. As they're marching towards your net debt target. And it looks like you gave a guide here for Q3 around buybacks. But just your thoughts around, you know, taking advantage of the 16% free cash flow yield. To the extent you're able to.
Brendan McCracken: Yeah. 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 look, you know, we look at this buyback through a fundamental lens. So we're not trying to be pro-cyclical 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 the shares are being priced well below that intrinsic value. And so 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 the shareholders. And what I'm particularly pleased about is that we're showing we can do that through the cycle.
Neil Mehta: Yeah. Hey, Brendan. And then the follow-up on the Montney with 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 strategy to make sure you're getting the best netbacks on this growing business?
Brendan McCracken: Yeah. Thanks, Neil, for highlighting that because that was an important feature to the announcement today, but then also to the profitability that we've been generating this year. So if you stand back from it, through 2025 here, we've been realizing 72% in NYMEX for our Canadian gas. That compares to AECO, which has through the same period through the 40% of NYMEX. So clearly, our diversification strategy is working. And, of course, you know, everybody is looking at the screen. You can see spot prices are even worse in AECO than that 40% today, materially worse. So but 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 gonna hand it over to Megan here in a sec to kinda comment as much as we can on the specifics. I would just say, you know, these deals take some time to negotiate, and so they were negotiated before this latest swoon in spot prices, and they are, you know, of 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, Megan, over to you on some of the details.
Megan Eilers: Yeah. Thanks, Neil. Thanks so much for recognizing this. These transactions are exciting milestones that do reinforce our strategy of gas price diversification. As Brendan noted, you know, 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'll have us receiving a percentage of JKM, for 50 MCF a day, and that begins in 2026 and goes through 2027. Our new Chicago deal is also physical delivery at AECO.
It'll have us receiving Chicago less d ducks on a 100 MMcf a day, which is a ten-year term beginning in 2027, and our two enhanced AECO deals are physical sales contracts with delivery in BC. Those agreements are gonna enhance our AECO netback on 70 MMcf a day. I mean, that's in effect now through 2027. And so the other thing I'd just like to point out is our JKM deal is particularly exciting as it gives Ovintiv Inc. its first exposure to LNG pricing. Nice team.
Brendan McCracken: Thanks, Neil.
Operator: Thank you. The next question comes from Kelly Ackerman at Bank of America. Please go ahead.
Kelly Ackerman: Hey, good morning, guys. Thanks for taking my question. 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? How many have you guys designed?
And if the wells that you're designing are a million and a half cheaper end to end, does that imply a more capital-efficient 2026?
Brendan McCracken: Yeah, Kelly. I'm gonna turn it over to Greg here to run through the details. But we planned for that $1.5 million reduction in our guidance, our original guidance. And so really, what you're seeing is us hit that target here, which we're pleased about. So those are already baked into both the original guide and the revised guidance that we issued today. But Greg, if you wanna cover the details there.
Greg Givens: Yeah. Thanks, Kelly, for the question. We couldn't be more pleased with how the team is executing on the integration here. And 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, you know, 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, you know, that program to where we already were on our program.
And so, you know, 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, you know, 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. So we're getting the benefit of being able to optimize them remotely. And, also, we're still on track, you know, with deferring a little capital from Q2 to Q3.
We're now online to bring our first end-to-end, Ovintiv Inc. designed and completed well in the Montney. That'll come online in November, which is, you know, really exciting for us because it's not only, you know, using the lower cost, but we're also testing several upside zones there. And we're excited to see how those wells perform. So everything is going really well. But essentially, as we've said, the improvements have been baked into our guidance. We'll try to improve a little from here, but, you know, the big step change has already occurred.
Kelly Ackerman: Got it. I appreciate that. My next one is on the Permian. So in that basin, you guys are a leader in completion, and I understand that to be a water system advantage. You got some peers that are looking at options to monetize those assets. Would you guys ever consider selling it?
Brendan McCracken: Yeah, Kelly. That's a great question. It's something we look at, you know, across all the different suite of ways we can create more shareholder value. I would comment the completions cost advantage and speed advantage that we've built up is more than just the water system. So 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 sand, local sand, and then the trim of frac design. So it is an all-of-the-above that's delivering this result, which is, I think, part of this stacked innovation strategy that we've been pursuing.
But as far as your question around monetizing the water infrastructure, it has a lot of value, has value to us, probably has value in the market as well, and it's something, you know, we evaluate on an ongoing basis.
Kelly Ackerman: Got it. I appreciate it. Thanks for the answers, guys.
Brendan McCracken: Yeah. Thank you.
Operator: Thank you. The next question comes from Philip Johnston at Capital One. Please go ahead.
Philip Johnston: Hey, thanks for the time. 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 of what's driving that decrease and also get a sense of how confident you are that you can achieve that reduction. Thanks.
Brendan McCracken: Yeah. Philip. Yeah. I appreciate the question, and, yeah, that's a good one to highlight as well. This is all performance-driven. So if we, you know, we came into the year, we all stretched back a little bit before year-end. We were running six rigs in the Permian. The combined Paramount, Ovintiv Inc. Montney Ovintiv Inc., Rig count was six. And so we've dropped, sorry. I think it was five. So we were six in the Permian, five in the Montney. We've now dropped both of those back to four and three respectively. And then we've gotten, as Greg has been highlighting, a lot faster with drilling and completions through the year too.
So really, what's happening is we're getting a bit of a front-end loaded feature because we're going so much faster with the activity performance. So it's all being driven by performance. So what that means is our activity profile, you know, is kind of staying consistent, but we're seeing capital come down in the fourth quarter is the lowest capital quarter in our guidance here.
Philip Johnston: Makes sense. Thanks, Brendan.
Brendan McCracken: Yep. Thanks, Philip.
Operator: Thank you. The next question comes from Greg Pardy at RBC Capital Markets. Please go ahead.
Greg Pardy: Yes. Hey, thanks. Good morning. 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?
Brendan McCracken: Yeah. Greg, love the question. Look, when it comes to this AI technology, it's obviously super nascent. So 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. So with the Montney tour, obviously, was unveiling what we're doing both on the drilling side when we took folks through our AI drill center. But then also 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 those same things are happening for our Permian and our Anadarko assets as well.
So across the whole portfolio, early days, we think the technical foundation that we've laid in here both on acquiring a unique and extensive private dataset but also the culture that we've built around innovation and technology adoption in the company are reasons why our performance is gonna be differentiated here.
Greg Pardy: Okay. That's helpful. And then I'll apologize, Corey, in advance because I'm gonna come back to the questions that have sort of been asked on shareholder returns. But just remind us what your net debt target is? And then essentially what happens when you hit that level? Is it conceivable you'd go to, like, a 100% buybacks or just curious as to what your thinking is there.
Corey Code: Yeah. So just on the target, we've talked about getting to a debt target of $4 billion, which, you know, at a mid-cycle price deck is about one times leverage for us. And so we've tried to remind people this year at current prices, we think we'll get below $5 billion. So, you know, that's not coming this year, but it's not that far away. As we get there towards the $4 billion, you know, obviously, there'd be more room for us to make different allocations, but we haven't committed that $4 billion as 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. So we haven't committed to what we'll do past that.
Greg Pardy: Okay. Understood. Thanks very much.
Corey Code: Yep. Thanks, Greg.
Operator: Thank you. The next question comes from David Deckelbaum at TD Cowen. Please go ahead.
David Deckelbaum: Thanks, everyone, for welcoming on the call. Brendan, I wanted to follow-up just on the Montney on a couple of things. One was just you talked about sort of the steady state of activity. You guys left your till target year the same sort of in that 80 net level. And you did about half this quarter. Should we be looking at that as more of a lumpiness around just the integration of the acquisition or are there some efficiency savings here that are kind of being, you know, perhaps restrained that would present a tailwind for '26?
Brendan McCracken: Yeah. The higher two q till in the was really off of the integration. So, you know, we took over those Paramount assets in January, and so there was a tail of higher activity. This was the combined five rigs going to three. So it was really kind of absorbing those wells and getting them completed fast and turned in line. So that's why that higher run rate in two q. And so 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.
David Deckelbaum: Appreciate that.
Brendan McCracken: Yep. And perhaps just following up a bit just to, you know, we talked about, obviously, getting to that $1.5 million of savings being baked in. And I know expectations are, you know, perhaps that continues to improve as you guys, you know, kinda do the full suite of completion on your side. But I guess as we're thinking about the broader portfolio, you trimmed CapEx in the Permian and the Anadarko on mostly efficiencies. And where we stand today do service cost present, you know, sort of a tailwind going into the '20 program at this point? It seems like a lot of the gains we've seen so far are more timing-oriented.
Brendan McCracken: Yeah. David, yeah, appreciate the question to surface that on the pricing side. So, yeah, what we're seeing in '25 here 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. You know, by category, there is some variance there, of course. But net-net, that's what we're seeing. So that's kind of matching our expectations. So really, inflation deflation is not a feature to 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, obviously, activity levels drop across North America, which is putting some pressure on the service pricing. So that's a place where we're sitting here today, probably optimistic on some deflation in '26, but, you know, let's let that play out and we'll integrate that into our '26 guidance. But, you know, directionally, that's where it's headed.
David Deckelbaum: Thank you. We'll stay tuned.
Brendan McCracken: Yep. Thanks, David.
Operator: Thank you. The next question comes from Geoff Jay at Daniel Energy Partners. Please go ahead.
Geoff Jay: Hey, guys. I was just thinking just wondering if you could kinda help me understand over the very long term, you know, the combination of cube development and your reoccupation strategy, how much do you think that lowers your reinvestment rate vis a vis sort of, I a more traditional approach or, you know, a more common approach to development?
Brendan McCracken: Yeah. I think what it's gonna do here is mean our reinvestment rate can continue where it's at and get better as we incorporate efficiencies. Whereas the traditional approach, you know, if you're not sort of taking the cube development approach, what that tends to lead to is step changes as your inventory degrades in quality. And so what we're insulating our investors with is sampling the remaining premium inventory that we have with every annual program, that's gonna lead to a very durable return on invested capital and free cash at constant prices over a long period of time.
And so we think that's the right way to be disciplined with our capital allocation, but also gonna be a real differentiated advantage for our investors in a maturing play type like Shale is today.
Geoff Jay: 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, etcetera, were maybe not as fully, I guess, deployed in the lower forty-eight. Is that not true? I just wonder if there's more to come, you know, sort of as there's more if there's more stuff to do at the lower forty-eight than there is in the Montney at the moment?
Brendan McCracken: Yeah. I think, I mean, all of this stuff is, like, less than a year into deployment. So it's still very much in the ramp-up phase. You know, Greg probably has some specific comments to add on the uniformity across the portfolio.
Greg Givens: Yeah. I think what I'd add, I mean, 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 year. So that's a really, you know, it's a legacy competency that we've been building on over time. We're building that same competency in the US, and maybe that's a little bit behind. So maybe that's what you sense. But the goal is gonna be, going forward, employ all of those latest, greatest workflows across all of the portfolio.
So we feel like we're kinda at the same place on DNC across all three assets and on the production optimization side, we might be a little bit ahead there in Canada, but working to get them all caught up.
Geoff Jay: Excellent. That's helpful. Thank you, guys.
Brendan McCracken: Thanks, Geoff.
Operator: Thank you. The next question comes from Josh Silverstein at UBS. Please go ahead.
Josh Silverstein: Hey. Thanks. Good morning, guys. Just wanted to walk through the Permian turn of light cadence for the year. You guys have clearly gotten off to a pretty good start there. And still looking at kind of 135 wells for the quarter. Just gonna walk through that because the production numbers for the first half were definitely stronger than expected.
Brendan McCracken: Yeah. I'll just flip it to Greg there. Thanks, Josh.
Greg Givens: Yeah. So just as a reminder, you know, 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 the running six rigs and then five rigs last year. We're now down to four rigs. So 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, completed our wells a little faster, which brought even a few more wells into the first half.
So what that allowed us to do, that execution along with, you know, really solid production performance, we shifted some complete spend from Q2 out into Q3, just to spread out the activity. Have a little more low-level program in the back half of the year. We're not changing the turn in line account for the full year. And keep in mind, sometimes these shifts are within quarters. So bring on wells in the first part of a quarter versus the back part of the quarter that may not show up on a turn in line count, but it 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. So that's our plan.
Josh Silverstein: Got it. And then, just coming off the monitor as well, obviously, a lot of focus on the DNC 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 more condensate-focused or scaff-focused up there. But it seems like there's still ways you guys to kinda chip away at that and maybe some goals there. Thanks.
Brendan McCracken: Yeah, Josh. No. That's great. I'm glad you highlighted that. I think, you know, 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. And so, you know, a couple of things in specific to the Montney. One of the other features that's helping us is our operating capability on the new assets has led to higher run times. And then, 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.
And so all of that is a boost to per unit OpEx because, you know, you're just being more effective with the dollars that you're spending. But, you know, Greg, I don't know if you want any comment on anything more specifically.
Greg Givens: Yeah. 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. You know, just further increases our ability to keep those wells online and optimized, up in Canada and then across the portfolio. One other thing that's really helping with the downtime is, while disruptions are less frequent, 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.
So all of those things lead to better production for the same or lower cost, which we think will have some, you know, downward pressure on LOE going forward.
Josh Silverstein: Thanks, guys.
Brendan McCracken: Thanks, Josh.
Operator: Thank you. At this time, we have completed the question and answer session, and we'll turn the call back over to Mr. Verhaest.
Jason Verhaest: Thanks, Joanna, and thank you, everyone, for joining us today. Our call is now complete.
Operator: Ladies and gentlemen, this concludes your conference.