Ovintiv Inc Q4 2025 Earnings Call Transcript

Ovintiv Inc (NYSE: OVV) Q4 2025 Earnings Call dated Feb. 24, 2026

Presentation

Operator

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv’s 2025 Fourth Quarter and Year-End Results Conference Call.

[Operator Instructions] Following the presentation, we will conduct a question-and-answer session.

Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing star one. For members of the media attending in a listen-only mode today, you may quote statements made by any of the Ovintiv representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Ovintiv.

I would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.

Jason Verhaest — Vice President, Investor Relations and Planning

Thanks, Joanna, and welcome, everyone, to our fourth quarter year-end 2025 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 the 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.

Brendan McCracken — President & Chief Executive Officer

Thanks, Jason. Good morning, everybody, and thank you for joining us. We are excited today to update the market on our latest results and the culmination of several years of strategic transformation at Ovintiv. With relentless focus and discipline, our team has remade our portfolio, reset our balance sheet, grown profitability and built one of the deepest inventory positions in our industry. We have done all that while delivering superior returns on invested capital, both through the drill bit, but also through smart transactions.

All along, we’ve been guided by a very simple formula. Superior and durable returns will accrue to the Company to build a deep inventory in the best resource creates a competitive execution advantage through its culture and expertise and has the discipline to allocate capital to the highest returns and get those returns on a full cycle basis all the way to the bottom line. Year-to-date, in 2026, we have closed the NuVista acquisition and reached an agreement to sell our Anadarko assets. This means our portfolio transformation is complete, and it leaves us with a very focused and high-quality portfolio in two of the best plays in North America, the Permian and the Montney. Proceeds from the Anadarko sale will go to the balance sheet, marking the achievement of our debt target and rightsizing our capital structure.

The enhanced resilience of the business means that we can return more cash to shareholders and the new shareholder return framework that we unveiled today does just that. Several years ago, we made the strategic decision to focus our portfolio and build high-quality inventory depth in the Permian and the Montney. Approximately 80% of the remaining sub $50 breakeven oil locations in North America are located in those two basins, bolstering our positions in these plays, where we have competitive advantage, means we can continue to deliver durable returns for many years to come. Since 2023, we’ve increased our Permian and Montney drilling inventory by more than 3,200 locations at an average cost of $1.4 million per net 10,000-foot locations, and we did it without diluting our shareholders or stressing our balance sheet. This inventory life expansion has been unmatched by our peers and leaves us with one of the most valuable inventory positions in the industry.

Our sequencing between inventory additions and debt reduction was carefully managed. We recognized the importance of reducing debt and we balanced that objective with timely transactions that our team generated to put our shareholders into premium inventory for the right price. This greatly extended our premium inventory duration. We have now cleared both of these hurdles, and that represents a material derisking event for our shareholders. As North American shale continues to mature, a very clear competitive advantage is emerging for companies like ours, that have already set their inventory position up for success, have a clean balance sheet and can access premium price markets and have a demonstrated track record that translates to leading edge efficiency and returns.

That combination of attributes is truly differentiated. Following the close of the Anadarko sale, which we expect will happen early in the second quarter, our net debt will be roughly $3.6 billion. This brings our leverage more in line with our peer group and opens the door for us to allocate a greater portion of our free cash flow to shareholder returns. The chart on the left of Slide 6 details the sources and uses of cash to get us to the $3.6 billion. If you’ll recall, we funded the NuVista acquisition with a balanced mix of cash and equity. The cash component was largely funded by a term loan. With the proceeds from the Anadarko sale, we plan to first pay out the term loan and our 2028 notes and then allocate the rest to our credit facility and commercial paper balance.

Our remaining long-term debt profile will have no maturities before 2030. We expect to realize $40 million of annualized interest savings from the repayment of the 2028 notes. This is in addition to the $25 million of annual savings we realized from paying out our 2026 notes earlier this year. We remain committed to our investment-grade credit rating, and we expect the Anadarko sale and subsequent deleveraging to be credit positive. With the Anadarko sales set to close in early Q2, we are in a position to increase our shareholder returns. We continue to believe that our equity is significantly undervalued and share buybacks continue to screen as an attractive return on investment.

Our new framework will allow us to be more opportunistic in addressing this valuation discount. In 2026, under the revised framework, we will plan to return at least 75% of our free cash flows to shareholders. Longer term, we have set the expected range from 50% to 100%. This wider range is intended to allow flexibility to accommodate commodity price volatility and avoid pro-cyclical buybacks. To be clear, our 2026 buyback target will be based off our full year free cash flow as we plan to make up for the pause that we had initially planned for this first quarter. We plan to commence buybacks immediately. In conjunction with our new framework, our Board of Directors has authorized a share buyback program totaling $3 billion.

I’ll now turn the call over to Corey to discuss our year-end results and 2026 guidance.

Corey Code — Executive Vice President & Chief Financial Officer

Thanks, Brendan. Our 2025 results demonstrate another year of execution excellence and strong financial performance. Our full year cash flow was $3.8 billion. We generated free cash flow of more than $1.6 billion, of which over $600 million was returned directly to our shareholders. Our focus on capital efficiency enabled us to produce more with less capital. Our initial guidance for 2025 had us delivering total volumes of 605,000 BOE per day for $2.2 billion of capital. Throughout the course of the year, we lowered our capital by $50 million and produced an additional 10,000 BOE per day of total volumes.

Importantly, we also continue to make progress on debt reduction, ending the year with less than $5.2 billion of net debt, a decrease of more than $240 million. Our solid execution in 2025 has set us up for continued success in 2026. Our strong operational performance during the fourth quarter delivered oil and condensate volumes averaging approximately 209,000 barrels per day at the high end of our guidance range and our capital investment of $465 million came in at the midpoint of our guidance. We also match or beat our per unit cost guide on every item, continuing to build on our track record as an industry-leading operator. Our fourth quarter cash flow per share at $3.81 beat consensus estimates by about 10% and our free cash flow totaled $508 million.

All in all, we delivered another strong quarter, both operationally and financially, which allowed us to enter 2026 with significant momentum. Maximizing capital efficiency and free cash flow remains a primary focus for our teams this year. We’re executing an oil-directed maintenance or stay-flat program with level-loaded activity in both the Permian and the Montney. The resulting oil and condensate run rates for each asset are roughly 120,000 barrels per day and about 85,000 barrels per day, respectively. Our 2026 program, including one quarter of Anadarko operations will deliver 209,000 barrels per day of oil and condensate, over two Bcf a day of natural gas and total production volumes of 620,000 BOE per day to 645,000 BOE per day or about $2.3 billion of capital investment.

When compared to the preliminary 2026 production outlook of 715,000 BOE per day we provided in November, the sale of the Anadarko reduces volumes by about 70,000 BOEs per day and the timing of the NuVista acquisition closing reduced those volumes by about 10,000 BOEs per day. We expect to see margin improvements in 2026 driven by lower LOE, production and mineral taxes and interest expense. Our T&P costs will increase this year as a result of greater Montney weighting in our portfolio, additional Montney processing capacity and increased market access in both plays, which enhances our netbacks. In the first quarter, we expect production to average approximately 670,000 BOEs per day including about 223,000 barrels per day of oil and condensate.

This will be the high point for the year. This includes roughly 3,000 BOE per day or 4,000 BOE per day of cold weather impact that we experienced across the U.S. assets in January. Our capital spend will also be the highest in the first quarter at about $625 million, largely due to $50 million of capital allocated to the Anadarko and some drilling activity in the Montney that we inherited from NuVista.

I’ll now turn the call over to Greg who will speak to our operational highlights.

Greg Givens — Executive Vice President & Chief Operating Officer

Thanks, Corey. Let’s dig into each of our two asset level development programs. Starting in the Permian, capital efficiency and free cash generation remain the top priorities as we work to drive efficiency in every aspect of our operations. Ovintiv is consistently one of the highest productivity, lowest cost operators in the basin. We recently received third-party recognition of our basin leadership from JPMorgan by being awarded the 2025 Order of Merit for Midland Basin Performance. Ovintiv had the highest three-month cumulative oil per foot again in 2025, and was the only operator who improved performance in each of the last three years. There are several factors that have contributed to our type curve improvement over that period of time.

And one of the bigger factors has been our use of surfactants and our completion designs. We’ve been studying surfactants for a number of years, both in the lab and in the field, and we pumped them in about 300 Permian wells since 2019. Compared to a similar group of analog or non-surfactant test treated wells, we see a 9% improvement in oil productivity. We believe surfactants account for roughly half of the type curve improvement we’ve observed in our Permian assets since 2022. We tested different chemical formulas across our acreage, and although performance varies by zone and by county, there is meaningful oil recovery benefit from the low-cost additives, which are highly economic. We will continue to hone our approach and trial different products across the acreage, but we are very pleased with the results we’ve achieved so far.

Our Permian team continues to set the efficient frontier when it comes to drilling and completions performance. We take great pride in our development approach and our ability to stack multiple innovations together to create industry-leading results. On completions, part of our success is from utilizing our real-time frac optimization. Every job we pumped is optimized in real time using proprietary algorithms, leveraging our vast private Permian data set. This also allows us to make real-time decisions, which improve well recovery and reduce costs, leading to better pad economics. We also made efficiency gains this year through use of continuous pumping. We pumped for seven straight days on our first trial, leading to a 20% improvement in completed feet per day. Our full year average completed feet per day was about 4,250.

This was more than 10% faster than our 2024 program average. On the drilling front, we have developed several in-house AI tools, which have allowed us to reduce cycle times, minimize failures and accelerate efficiency gains. Our 2025 drilling speed averaged more than 2,000 feet per day for the second consecutive year. Our pace-setter well was over 3,000 feet per day, so we’ll look to continue improving on what we believe are basin-leading results. These cycle time improvements are driving over well costs. Our 2026 expected drilling and completion cost is among the best in the industry at less than $600 per foot, which is about $25 per foot lower than last year. The 136 net wells we brought online in the Permian in 2025 continue to meet or slightly exceed our 2025 type curve. This type curve was unchanged across the year, and it remains unchanged in 2026.

This year, we plan to run a load-level program with five rigs and one to two frac crews to bring on about 130 net wells. We plan to hold oil and condensate production at roughly 120,000 barrels per day. While our Permian economics are driven by oil, it’s important to note that we now have about 150 million cubic feet per day of firm transport leaving the basin for our Permian natural gas volumes. This means that roughly 55% of our 2026 gas production will be priced at the Gulf Coast instead of Waha. Last year, our unhedged Permian gas price realization averaged $1.55 per Mcf, about 179% of Waha.

Moving north to the Montney, we remain very pleased with the tremendous depth and quality we have added to our acreage in the heart of the Alberta oil window over the last year. We are very excited to have the NuVista assets in our portfolio, and we are already working to integrate them into our business as safely and efficiently as possible. As a reminder, we plan to deliver well cost savings of $1 million per well across the acquired assets through the application of our industry-leading approach to drilling, completion and production operations. We demonstrated our ability to capture similar cost synergies last year as we integrated the Paramount assets into our business. The swift achievement of those synergies is a real testament to the culture and capability of our Montney team. We couldn’t be more pleased with how those assets have performed.

We quickly achieved our well cost savings target of $1.5 million per well, took 14 days out of the drilling cycle time and successfully tested the upside potential of the asset with a higher density development. At our 15 or 16 pad, we added a third bench and increased density to 14 wells per section, and we’re seeing initial productivity rates that are exceeding our expectations. These results have unlocked roughly 130 upside locations across our Montney acreage. This year, we plan to run six rigs and one to two frac spreads to bring on about 135 net turn-in lines. We plan to focus roughly a third of our activity on the newly acquired NuVista acreage, a third on the legacy Paramount lands and a third will be split between our legacy Pipestone and Cutbank Ridge areas. Current production from the Montney is in line with our previously communicated run rate of about 85,000 barrels per day of oil and condensate.

We are maintaining a repeatable type curve, and although individual wells in the play will display a range of oil mix, the aggregated program delivers very predictable results. Due to some planned plant turnarounds, Montney production in the second quarter is expected to be at the lower end of our full year guidance range of 83,000 barrels per day to 87,000 barrels per day and 1.75 Bcf per day to 1.85 Bcf per day of natural gas while we are working with our midstream providers to minimize the downtime as much as possible. In 2026, we expect our D&C cost to average less than $500 per foot. This is about $25 per foot less than our 2025 well cost. Part of the decrease year-over-year is thanks to faster cycle times as well as greater use of domestic sand in our 2026 completions. Roughly half of our 2026 Montney wells will be completed with locally sourced sand. Overall, the asset is performing very well and a low-cost, high-productivity nature of the wells has meant we’ve consistently been able to generate highly competitive economics from the play throughout the commodity price cycle.

I’ll now turn the call back to Brendan.

Brendan McCracken — President & Chief Executive Officer

Thanks, Greg. Over the last few years, we’ve worked hard to high grade and focus our portfolio, build extensive inventory depth, drive profitability and reduce our leverage. Over that time, our team has delivered outstanding results. Those results demonstrate that our strategy is working and our execution excellence is translating into increased value for our shareholders. We’ve been very intentional about building a high-quality business. We’ve demonstrated along the way that we are disciplined stewards of our shareholders’ capital. We will continue to be relentless about making our business more profitable and more valuable every day, but we’ve reached a new period of stability, and we are excited to unlock the full value of what we’ve built.

This concludes our prepared remarks. Operator, we’re now ready to turn the line back for questions.

Question & Answers

Operator

Thank you. [Operator Instructions] We will now begin the question-and-answer session and go to the first caller. First question comes from Arun Jayaram at JPMorgan. Please go ahead.

Arun Jayaram

Yeah, good morning, Brendan and team. I was wondering if you could maybe elaborate on the change to your shareholder returns program in ’26, where you’re increasing the mix to 75% from 50%. And thoughts, Brendan, how we should think about the mix of shareholder returns post 2026 relative to the 50% to 100% long-term range?

Brendan McCracken — President & Chief Executive Officer

Yeah. Thanks, Arun. Good morning. Yeah. So today, we see a lot of value in our equity. And when we close the Anadarko, we expect to be at about $3.6 billion of debt. And so that’s really the reason for shifting to the upper end of the range this year. And then longer term, we’ve set a wider range. And really, the thinking here is we want this framework to be durable through the commodity price cycle. And in particular, we want to avoid setting up a procyclical framework. And what I mean by that is when commodity prices are high, you probably should expect us to be more towards the low end of that 50% to 100% range.

And what that allows us to do is be banking that windfall, if you will, when commodity prices are well above mid-cycle, be banking that windfall permanently into the capital structure. And then on the flip side, in periods of lower commodity prices below the mid-cycle level, that could push us to the higher end of the range where we’re likely to see more value in the equity. So that’s the only thinking behind the longer-term 50% to 100% range, and we’ll have the ability to flex around that. But when we see value like we do in the equity today, then the upper end of the range is appealing.

Arun Jayaram

Great. Brendan, my follow-up, we were very interested in the surfactant program, and perhaps we’re surprised that you guys have been doing it for so long. So I was wondering if you could maybe unpack some of the details on the program. It looks to be driving some productivity gains versus control wells. And it looks like you’re using surfactants more on the completion end or the front end of the well life cycle. Maybe talk about the cost benefit and wondering if you have tested surfactants in terms of moderating your base declines as a couple of your peers have highlighted thus far.

Brendan McCracken — President & Chief Executive Officer

Yeah, I love the question, Arun. Yeah, there’s a lot going on in the Company today. So glad you dug in on that surfactant piece. I’ll maybe just set up a couple of comments here and then kick it over to Greg on the details, but this is just another example of the stacked innovation that we’ve been talking about. And really for a few years now, we’ve been emphasizing three key features in our completion design that we think are adding value, adding to our type curves. And we’ve been calling it fluid chemistry. We were kind of deliberately trying to keep it quiet on exactly what we were doing because we felt like we had kind of got out ahead of others in this space and that’s what you’re seeing show off today with 300 [Phonetic] results already. That’s really helped push us to the top of the leaderboard on Permian productivity. So that’s kind of a bit of the background, but I’ll kick it to Greg here to talk about some of the specifics.

Greg Givens — Executive Vice President & Chief Operating Officer

Yeah. Thanks, Brendan. And thanks, Arun, for the question. And yes, you highlighted it correctly, we are focusing our surfactant program on the initial completions. This is something we’ve been working on for a number of years, and the team continues to make breakthroughs and build our confidence in this space. So maybe just a little bit about what we’re doing. So these surfactants that we’re pumping, there are liquid additives that we include in our frac fluid that are designed to improve oil recovery in the reservoir downhole. So once you pump them downhole, they change the surface tension of the fluids which allows more of the oil to be released from the rock, flow into the fracture and then out the wellbore, increasing recovery, not just in the short, but in the longer term as we’ve demonstrated over the last several years.

We’ve been working for a number of years on this, both in the lab and in the field. So we’ve done core testing in the labs as well as field trials to try to determine which surfactants work best and which zones. We’ve been working to optimize the concentrations that we pump. So the amount of surfactant per ratio of fluid, both to optimize the effectiveness but also optimize the cost of these surfactants. And so far, we pumped, as we said in the prepared remarks, surfactants in around 300 wells generating that 9% uplift, but that’s been a progression over time. So we started out in the early years with some field trials, gained confidence. And more recently, last year, we pumped surfactants in about 75% of the completions we’ve pumped in the Midland Basin and saw very good results with that. We would anticipate pumping a smaller amount this year in 2026.

So we’ve been very pleased with the results on our completions. We’ve also tested it to some degree in producing wells. Haven’t seen quite the effectiveness there. And so that is a very small part of the program. But the continue — the team continues to experiment with this and will continue going forward. But we do believe it’s a very effective way to improve recovery in the near and long term from these wells. And we think it’s going to — it has been and will continue to be a big reason for our outperformance in the Permian.

Arun Jayaram

Great. Thanks a lot.

Brendan McCracken — President & Chief Executive Officer

Thanks, Arun.

Operator

Thank you. The next question comes from Lloyd Byrne with Jefferies. Please go ahead.

Lloyd Byrne — Analyst, Jefferies

Hey, good morning, guys. Congrats on the transformation. I know it’s been a long process. Maybe I wanted to ask about the surfactants a little bit as well and maybe Greg can talk about — a little bit about costs per well. And how are you seeing that go forward? I know you’re just in the early stages, but if you have a 9% improvement, are the costs going up as well?

Brendan McCracken — President & Chief Executive Officer

Hey, Lloyd, yeah, so this is an interesting question. So when we first started this work several years ago, there was some really expensive chemistry out there that was a real barrier to pumping it more broadly just because of the risk reward feature and what our lab work has really let us do is trial hundreds and hundreds of different chemistries here, which allows us to then create substitutes that have now kind of almost completely displaced some of those original chemistries that were in the market several years ago.

So Greg commented on one of the things we’ve been fine-tuning is the amount of surfactant that we’ve been pumping, but the other feature has been substituting cheaper and cheaper alternatives. So we’ve been a little reluctant to be specific about some of this here because we’re trying to protect what we think is an advantage. But it’s in the hundreds of thousands of dollars a well is probably a good way to think about it.

Lloyd Byrne — Analyst, Jefferies

Okay, thanks. And then just as a follow-up, you’ve kind of moved from four basins to two basins and just what kind of opportunity does that give you to cut costs maybe from an organizational structure as well?

Brendan McCracken — President & Chief Executive Officer

Yeah. So really appreciate that, Lloyd. With this latest transaction, we pointed to is $100 million of synergies, but we also pointed to several synergies that we didn’t quantify at this time. And we think those are going to show up on the infrastructure side. We saw that with the Paramount integration. And really, now we’re kind of stitching together our legacy infrastructure, the Paramount infrastructure and then now the NuVista infrastructure, all three of those overlap. And so there’s going to be some of those synergies realized, and we look forward to updating the market on those as we get deeper into the year. And then there’s going to be some organizational synergy here, too.

Everyone on our team has done just a tremendous job working safely through a lot of change at our Company and created a lot of shareholder value. And so I do want to recognize their effort and the results that they have delivered. And we’ve taken big steps to simplify the portfolio, and so we will be redesigning our organization to match that new portfolio. And we expect to have those changes completed shortly after the Anadarko divestiture, and we’ll update the market on the impact of those once we get there.

Lloyd Byrne — Analyst, Jefferies

Great. Congratulations again.

Brendan McCracken — President & Chief Executive Officer

Thanks, Lloyd.

Operator

Thank you. The next question comes from Neal Dingmann with William Blair. Please go ahead.

Neal Dingmann — Analyst, William Blair

Good morning, guys. Nice quarter. Brendan, my question is just on the Montney. I’m just wondering, looking at, looks at the activity, looking like maybe, right, about a third of activity coming from the NuVista, one-third Paramount and one-third, the prior position. And I’m just wondering if so, do you anticipate sort of similar activity across the board like that, and are those well results pretty similar across the board?

Brendan McCracken — President & Chief Executive Officer

Yeah, Neal, you got it, Neal. That’s about the activity cadence going forward is going to be that one-third, one-third, one-third. And just a quick comment on the driver for that. That’s really an outcome of our reoccupation strategy. And folks will remember that’s the strategy we pursue both in the Permian and the Montney to maximize value from our acreage as we manage the interactions between cubes. So a lot has been made over the last several years about the inter-well effect of co-development or cube development, but there is also inter-cube effect as we drill a new cube beside an existing cube.

And so that is a governing feature of our development programs. And so that in those small part drives that allocation of activity as we just continue to mow the yard across our acreage position in both the Montney and the Permian. So that’s the big driver of that piece there.

Neal Dingmann — Analyst, William Blair

That makes sense. And maybe just a second one on that same vein for you, either you or Greg, just maybe more in the Permian development. Can I assume that the development will continue to consist mostly exclusively of cube development? And if so, is well spacing staying relatively the same there or is there any changes?

Greg Givens — Executive Vice President & Chief Operating Officer

Yeah. Thanks for the question, Neal. Yeah, in the Permian, we continue to optimize and make small tweaks over time to our well spacing to account for the existing cubes or parent wells in an area, but overall, we’re still using the same approach. We complete the entire cube at the same time, come back 18 months later and complete the offset cube, getting all of the zones at the same time at a fairly similar spacing, and that’s allowing us to get very consistent results year-over-year. So we’re not saving any lesser zones to come back later when they would be disadvantaged. We’re getting the whole cube at the same time, and that’s working quite well for us. So no major changes there.

Neal Dingmann — Analyst, William Blair

Good to hear. Thanks, Greg.

Greg Givens — Executive Vice President & Chief Operating Officer

Thanks, Neal.

Operator

Thank you. The next question comes from Neil Mehta with Goldman Sachs. Please go ahead.

Neil Mehta — Analyst, Goldman Sachs

Yeah, thanks so much, and Brendan, congratulations on, again, this transformation over the last five years and maybe that’s kind of the key question for me, which is, have you gotten the portfolio to the optimal level where you — I think when you took over, you were in six areas, now you’re at two areas. Are you in your sweet spot? Does that mean that there’s a pause on M&A as you digest all this and the incremental dollar really is to the buyback, or is there another leg to the story that you’re still exploring?

Brendan McCracken — President & Chief Executive Officer

Yeah. Thanks, Neil. Yeah, the portfolio transition here is complete. So we’ve clearly planted our flag in the Montney and the Permian, where we have competitive advantage and where we see the best resource. And we’ve built one of the longest duration inventory positions while we did that. And so we really believe that stability has real value for our investors, and we look forward to continuing to unlock the full value from what we built.

Neil Mehta — Analyst, Goldman Sachs

Okay. I appreciate that. And then just a follow-up is just on the shape of both production and capex through the year. I guess, Q1 is a little bit heavier, but I’m guessing that’s part of that’s just the pro forma portfolio. And then Q2, you’ve got a little bit more maintenance in Montney. So can you just talk about how you’re thinking about the cadence for production, quarterly cadence of production and then capital through the year?

Brendan McCracken — President & Chief Executive Officer

Yeah, great. You nailed it exactly, Neil. So a little bit higher capital in Q1 is absolutely just the Anadarko effect. And so once we close that, that will come out and we’ll just run rate out and I think we’ve probably said transition or transformation, the highest word count of this call so far. But one of the other pieces that we’ve transformed is the low level nature of our programs, and that has been over multiple years here to shift to a fully low level program. And really, we’ve got that as a really key feature in 2026. So we really like how we’ve leveled out that and it just creates more predictable and stable business to operate within.

Neil Mehta — Analyst, Goldman Sachs

Thanks, Brendan.

Brendan McCracken — President & Chief Executive Officer

Yeah, thanks, Neil.

Operator

Thank you. The next question comes from Greg Pardy with RBC Capital Markets. Please go ahead.

Greg Pardy — Analyst, RBC Capital Markets

Yeah, thanks. Good morning. I had really a couple of technical questions. I was curious, just first, how much of an opportunity is there with respect to this using in-basin sand? I caught some of Greg’s comments or Brendan, in your comments. But I’m just wondering, has that been perhaps optimized in both the Montney and the Permian.

Brendan McCracken — President & Chief Executive Officer

Yeah. I love the question, Greg. Yeah. So we’re really excited about the in-basin sand results that we’re already delivering in the Permian and really excited about the evolution that’s going on in the Montney as we shift more and more to domestic and wet sand in the Montney too. And this is another great example of stacked innovation, creating value for us. And also a great example of knowledge transfer and value between the two pieces of our portfolio because this is obviously something that we led the charge on in the Permian and now are leading the charge on in Canada and in the Montney. So maybe, Greg, if you want to give a few comments around the percentage of utilization and where we’re headed there.

Greg Givens — Executive Vice President & Chief Operating Officer

Yeah. Thanks, Brendan. Yeah, Greg, so on the Permian side, we’ve been at local wet sand for a number of years and essentially 100% of our program is going to be local wet sand from mines there in the field. And so we’re continuing to refine that process with our sand pile and our delivery systems, but that’s a fairly mature program. The new news over the last year or so is moving some of that technology north of the border. As you know, historically, most operators will be taking Northern White Sand by rail from the U.S. up to Canada, and that just adds a whole lot of cost.

And so we’ve been working with providers there to use more local domestic sand. The sources aren’t quite as close to the field, but there are good sand sources. And this year, we’re going to have roughly 50% of our sand pumped will be domestic sand. They’re sourced in Canada. So you eliminate that rail charge, you were able to lower cost dramatically. We’ve also begun testing wet sand in Canada, and it works quite well. This time of year, we joke it’s a little crunchier, but it still goes downhole just the same. And that is an evolving technology that we think we’re going to be able to use more and more over time. So we should see some of the same efficiencies we saw in the Permian and some of the cost reduction, but a little more nascent in Canada than it is in the Permian but still working quite well.

Greg Pardy — Analyst, RBC Capital Markets

Okay. Thanks for that. And then I’ll maybe just kind of stay with Montney now. When you kind of compare and contrast NuVista versus the Paramount acquisition. Can you — how do you look at perhaps the degree of low-hanging fruit cost synergies, efficiencies and things like that? I think, Brendan, in the past, you’ve mentioned NuVista was actually a pretty good operator. I’m just curious on the two.

Brendan McCracken — President & Chief Executive Officer

Yeah, I think — I mean, I’ll start with geography first and then just come on to — Greg will have some comments on the integration. But the NuVista piece really fills in the jigsaw puzzle. And so with Paramount, we stepped further South than we had been with our legacy, not by a long ways, but — and we were, I think, had the right amount of humility there to make sure when we integrated those assets that we didn’t change something inadvertently and create risk in the integration. And so we stepped our way in a very thoughtful integration process through really a full year here.

And one of the highlights in the deck today, again, there’s a lot in there, but one of the highlights in there is pointing to the really strong results we’re seeing from our first density pad, and we’re excited about those. And then with — in contrast, NuVista really filling in the jigsaw piece in between. We just have a lot more technical confidence and we’re kind of integrating quite quickly there with that piece. But Greg, if you want to comment on some of the specifics about how it’s going.

Greg Givens — Executive Vice President & Chief Operating Officer

Yeah, for sure. Yeah, I think Brendan set it up really well. It’s going to be the same process on NuVista as it was on Paramount. It’s just going to go a little faster. So because of our familiarity with the assets plus all of the learnings we had on the Paramount integration, we’re going to try to accelerate things a little, and we think that that’s very doable. So the team is already hard at work, employing the same playbook that we’ve used on all the last [Phonetic] transactions. We came in day one, took over the asset. We had a short safety orientation and then got to work. So by that afternoon, we were operating the asset as Ovintiv.

There’s only been a few short weeks, but we’ve already connected all the producing wells to our operations control center so that we can optimize production to minimize downtime. We’ve linked the drilling rigs to our DRIVE Center, which is our optimization tool where we use AI to help optimize drilling performance, and that’s going to allow us to deliver our synergies here very quickly. We’ve already incorporated the $1 million per well of savings, the synergy savings, or what you’re seeing as part of the guidance.

We’re going to be delivering that from day one. And so, so far, we’ve had really, really good results. The teams are integrating well. The new wells remain drilled as expected. As I mentioned earlier, production is already at 85,000 barrels a day, which is what we expected for the assets as they come together. So integration is going quite well. Just really, really pleased, and I think it will be very similar to the last time. It will just go a little faster and hopefully be even more effective.

Brendan McCracken — President & Chief Executive Officer

Greg, that high density test results on Slide 14 there, which was the 14 wells per section that we talked about when we started out with the transition of the Paramount, integration of the Paramount assets. And so that does move 130 wells out of upside into the premium bucket for us. So a really critical result.

Greg Pardy — Analyst, RBC Capital Markets

Terrific. Yeah, thanks for the rundown and congrats on the transformation.

Brendan McCracken — President & Chief Executive Officer

Thank you, Greg.

Operator

Thank you. The next question comes from Josh Silverstein at UBS. Please go ahead.

Josh Silverstein

Hey, thanks. Good morning, guys. From a balance perspective, pro forma, you’re now below that $4 billion long-term target that you’ve had for a while now. How should we think about the right level of debt for you guys going forward? Should we think about it as kind of an absolute level or a net debt level to kind of think about free cash flow allocation? Thanks.

Brendan McCracken — President & Chief Executive Officer

Yeah. Hey, Josh. So yes. So we’ve reached that target. In fact, we’re going to move past it here with the Anadarko proceeds. So really, we’re not setting a new target here. If you remember, the $4 billion net target that we set was really a trigger for increased shareholder returns. And we spent obviously a lot of time and effort getting us to this spot. So that is now happening.

That trigger is pulled and the catalyst to change those returns is going to be up and running right after we get off this call, I guess. And so we’ve had to balance that debt reduction as part of our capital allocation for a long time. We’ve now put ourselves into this resilient position. So — and at the same time, we put the inventory into a really strong and resilient position as well. So it just means we’re in a place here now we can focus on keeping the debt around this level and focus on allocating more to cash returns. So that’s how we’re thinking about the debt level go forward.

Josh Silverstein

Got it. And then from a Montney operating perspective, I know you guys on the Paramount transaction were able to kind of optimize the infrastructure a bit more. Can you talk about what you might be able to do on the NuVista asset as well to kind of improve the overall productivity here and then maybe from a long-term planning perspective, is there anything you guys are thinking about from an infrastructure standpoint that you may need to invest in or want from a third-party build? Thanks.

Brendan McCracken — President & Chief Executive Officer

Yeah, I’ll turn it over to Greg here, but we are excited about taking these sort of three disparate systems that were previously all operated independently and being able to have one value-creating mindset over all three of them. But Greg, you can comment.

Greg Givens — Executive Vice President & Chief Operating Officer

Yeah. Thanks for the question. And so in the short term, we’re really focused on getting the well cost savings at the well level, putting in our completion designs, our facilities designs. And that’s going to take place over here like immediately over the coming months. Longer term though, we’re really excited about the opportunity to optimize infrastructure.

If you look at the map, it’s just reeks of opportunity. When you look at how well the three positions come together, the gas plants, how close they are to each other, the number of midstream lines that are crossing the asset. So a little more work to do there. It’s a little more time consuming to work with the midstreamers to make sure we’re doing the most efficient operations there. But over time, that’s something we’re going to target to get our T&P down to get the gas molecules for the most efficient plant and to work through those things. So that’s coming a little longer. But in the short term, we’re really excited about the well cost savings. Longer term, we think the midstream, there’s a lot of opportunity there, and that will be something we’ll start working on here immediately.

Josh Silverstein

Great. Thanks, guys.

Brendan McCracken — President & Chief Executive Officer

Thanks, Josh.

Operator

Thank you. The next question comes from Doug Leggate with Wolfe Research. Please go ahead.

Doug Leggate — Analyst, Wolfe Research

Hey, good morning, everybody. Brendan, I wonder if I could ask you about asset duration and how you define that. The portfolio repositioning is extraordinary as everybody has observed. But I’m trying to understand, when I asked this question to Diamondback this morning as well, is this idea between sustaining production or drilling depth versus sustaining free cash flow? How do you think about that in the portfolio? What are you trying to solve for?

Brendan McCracken — President & Chief Executive Officer

Yeah. I mean we haven’t been exotic with our thinking there. We just run it off of what it takes to sustain the production. And in a lot of ways, what we’ve been talking about, Doug, is the ability to sustain the returns that we’re generating today while we do that production maintenance level and this, again, at the risk of being too pedantic with it. This is why the reoccupation strategy and how we’ve approached both cube development but also program design really derisk our inventory duration over time.

And just as a refresher here, because we’re designing our annual programs with that reoccupation in mind, so to come back sort of 12 months — sorry, 18 months to 24 months after we’ve drilled the prior cubes because that’s been the dominant feature of our program design. We essentially are sampling all of our remaining inventory with a full year development program, either in the Permian or the Montney. So what that means is we already know what the remaining duration inventory and how it’s going to perform because we’re drilling it today. We’re not saving the worst locations for a decade from now.

We’re kind of drilling the full cubes and then reoccupying cubes as we go. So I believe that to be a big derisker. But one of the other things that’s important on this front is if we were telling you that, that was what we were doing, and we were delivering mediocre results, I think that would be up for question, but we’re delivering leading results while we’re doing that. And I think that’s the true differentiation.

Doug Leggate — Analyst, Wolfe Research

I appreciate that answer. I know it’s a bit nuanced more than anything else. But forgive me for my second one, but you’re probably not going to talk about capital structure and all that stuff. But I want to ask you about your philosophical view as the CEO about your commitment to cash returns. Because if I play back to you what you just said today, you do not want to be guilty of procyclical buybacks. But that’s exactly what you’re doing in 2026, if I may say so, meaning that your stock is up 25%. ExxonMobil is up 22%. Oil is about 70% for reasons we all know are not necessarily fundamental. And this is the year you’re going for 75% of your free cash flow per share buyback. Why are you not choosing to be more discretionary in your timing?

Brendan McCracken — President & Chief Executive Officer

Yeah. I’m going to try and not be — I guess I am going to still try and be humble here, but 30% still doesn’t get us to what we think is a reasonable valuation for the stock. So I’m not trying to say that, that’s not great, and we’re pleased, obviously, with the momentum, but we still see a lot of intrinsic value in the equity today. When we talk about trying to avoid being procyclical, a lot of that is going to be tied, as you know, Doug, to the commodity environment.

And today, we’re not in a commodity environment that screams really high windfall situation, I think we’re still in a relatively modest commodity environment today. And so we do not see the risk of being at 75% as a procyclical risk today because of that intrinsic value gap we still see in the equity.

Doug Leggate — Analyst, Wolfe Research

All right, I wanted to take the question. Thanks so much.

Brendan McCracken — President & Chief Executive Officer

Yeah, thanks, Doug.

Operator

Thank you. The next question comes from Kalei Akamine with Bank of America. Please go ahead.

Kalei Akamine — Analyst, Bank Of America

Hey, good morning, guys. My question is on the 15 pads, 16 pads. So maybe this is for Greg. Greg, wondering if you can talk about how you sequence the completions of the three zones and share any details on the frac job. That third zone has been an opportunity in the area. It sounds like you guys have cracked the code. And then where in the basin next do you plan to apply that design? And could the balance of the upside locations move into the derisked in-store account this year?

Brendan McCracken — President & Chief Executive Officer

Yeah, I will turn it to Greg. Thanks, Kalei.

Greg Givens — Executive Vice President & Chief Operating Officer

Sorry, I had trouble turning my mic on. Yeah. So I appreciate the question. And we’re really, really pleased with the results there on this 15 pad to 16 pad down in Karr. So what the team has done there, just as a reminder, when we acquired the asset, our base case was 12 wells a section. We said we had upside up to 16 wells. So this is the first pad that we really got to design to end in the area. And so we kind of met in the middle with 14 wells per section spacing. So we added that third zone down in the Lower Montney or the Sexsmith, some call it and also increased density in the upper part of the cube. Pumped a fairly normal frac design for us, which might be a little more intensity than some of the peers are pumping in the area, but it’s a fairly normal frac design.

It was really the stacking and spacing that we leaned in on. And so far, we’re really pleased. The pad has been online a little over 100 days. The lower zones actually exceeding expectations of what we were expecting. And then the upper zones are holding up very nicely despite the increased density. So our plans now are to move to other parts there of Karr and employ this density test — or sorry, density design now. And that’s why we’ve talked about 130 of the, call it, roughly 600 upside locations between the two deals. This proves up 130 of those.

So the next step will be to go to other parts of Karr in testing the third zone. And then we’ve still got work to do up in Wapiti and then in other parts of the acreage. So we’ll be systematic about this. One pad doesn’t prove up all the upside, but we’ll continue to execute with this design on our future pads and then maybe even lean in a little more, we still have a little more upside potentially up to 16 wells per section on a few of the pads. So really pleased. I wanted to wait until we had a few months under our belt before we talked about this one, and right now, we’re feeling really good about it.

Kalei Akamine — Analyst, Bank Of America

Thanks for that detail, Greg. Maybe staying with the Montney here. The second question is on the plant turnaround in 2Q. We understand that was elected by the midstream operator. How should we be thinking about the cadence of turnaround activity in the Montney? Is it annual? How much heads up does the operator typically give you that turnaround is needed? And should we expect better performance from these plants and maybe that’s a yield after this work has been completed?

Greg Givens — Executive Vice President & Chief Operating Officer

No, I appreciate the question, Kalei. This is fairly normal operations from the midstream processing plants up in Canada. They’re on schedules that every two years to three years, you take down the plant for a few weeks to do inspections, routine maintenance, maybe upgrade a few of the vessels. So these are the kind of things that we’re usually, we know about well in advance. That’s why we’re talking to you now about something that’s going to happen next quarter. What we’re experiencing in this coming quarter as we just happen to have five of them, which are all lined up at the same time.

And so normally, we don’t really have to talk much about these because you may have one or two turnarounds going on at the same time and you can move volumes around. But when you end up having five at once all lining up at the same time, it just takes a little more coordination. So we’re working with the midstreamers to try to minimize the amount of time that they’re down, try to move volumes around them where we can. But right now, we do feel like there will be some impact. And that’s why we’re guiding to be at the lower end of that 83,000 barrels per day to 87,000 barrels per day in the Montney. But this is something that I’d say it’s fairly infrequent that they all line up in the same quarter.

Usually, they’re more spread out over time and they’re more manageable. So I don’t think this is a longer-term risk for us. This is just something the way the stars lined. We wanted to let everyone know that this was coming and that we’re planning for it. So that when we come back and report Q2 earnings, there’s no surprises. So just trying to give you guys a heads up, but trust that we’re working to try to minimize the impact as much as we can.

Kalei Akamine — Analyst, Bank Of America

And Greg, just to follow up, coming out of maintenance, could there be any increase in the performance in those plants, maybe that’s in yield after that work is done?

Greg Givens — Executive Vice President & Chief Operating Officer

That’s going to vary by facility and exactly what kind of work they’re doing. But usually, these are not upgrades that add capacity. These are more routine maintenance. Think of changing the oil in your car, it probably isn’t going to run a whole lot better after you’re done, but in some cases, we could see some minor improvement or flush production. But for the most part, this is just routine maintenance, routine work that they’re doing.

Kalei Akamine — Analyst, Bank Of America

Thank you, Greg.

Brendan McCracken — President & Chief Executive Officer

Thanks, Kalei.

Operator

Thank you. The next question comes from Betty Jiang at Barclays. Please go ahead.

Betty Jiang

Good morning. Congrats again on the portfolio transformation and maybe into the buyback. My first question on the Permian. If you don’t mind me digging into the numbers a bit, but your lateral length is higher year-on-year. And so on a total net tail [Phonetic] footage basis, it’s almost up high single digits year-on-year, but holding production flat, even though type curve is unchanged, what we would typically expect some upside to that production. So could you just unpack the dynamic there? And if we hold up that Permian production flat, where could the capex trend on a normalized basis going forward?

Brendan McCracken — President & Chief Executive Officer

Yeah, this is great, Betty. I’ll turn it to Greg. Here — the headline here is we are seeing an efficiency gain on the well cost side. So about 5% down on the well costs year-over-year and then holding the type curve flat. So what you’ll see over time is that this is going to translate through into the total program, but there’s some timing effects for 2025 — 2026 that are kind of masking that a bit here, but Greg can cover that.

Greg Givens — Executive Vice President & Chief Operating Officer

Yeah. So thanks for the question. And so as we’ve been talking about today, we really like to usually run our programs on a very level-loaded basis, at least that’s been our goal. We’ve tried to complete our wells as soon as are drilled. So we don’t carry excessive DUCs. But as you might recall, last year, we had a number of extra DUCs coming into the year. So in the first quarter of ’25, we employed a spot frac crew in the Permian and came in and finished out all of those DUCs, which it had a couple of impacts to our program.

One, capital was actually artificially low last year because for all of those DUCs, the drilling capital was in the previous year, and they only — we only saw the completion capital last year. And the other result was we actually saw a really nice production boost there in the first quarter. We brought on over 50 wells in the first quarter, which was about double our run rate for the other quarters in the year. So really positive for last year.

Unfortunately, for the metrics, we don’t have that same circumstance this year. But we do have a very level-loaded program that we feel very good about. It allows us to become more efficient and continue to execute very repeatedly when we do the same number of completions, same amount of capital, same production every quarter. And so if you think about the building blocks of the guide, you’ve got a slightly lower cost per foot, same type curve. So really, the only difference is the timing. And so that’s what you’re seeing manifest as it rolls through the numbers. But over time, we feel like this is going to be a very efficient program that’s going to continue to get better over time as we continue to drive down the costs and keep that type curve flat.

Betty Jiang

Thank you for the clarification there. My follow-up is on the Montney surfactant use. I mean it seems a lot of operational efficiency tailwind in Montney, but specifically, are you testing the surfactants in Montney as well? Is there any read across and viability there?

Brendan McCracken — President & Chief Executive Officer

Yeah, I think I’ll set Greg up here, but what we found and understood really from the early days of this is every bench in each county are going to perform a little bit differently depending on the wettability and the fluids that we’re trying to impact. And so — and the Montney does have a wholly different down subsurface regime from temperature and pressure perspective. So it’s going to have its own bespoke completion optimization.

Some of that might be surfactant. Some of it is looking like other pieces that can add to the performance that we’re seeing there. So it will be a little bit different. We’re quite a ways further advanced on surfactants in the Permian with 300 wells pumped there. We’ve done nowhere near that many in Montney to this point, but really excited about completion design in the Montney generally. We’ll see surfactants were going to go a little slower there just because of the temperature and pressure differences. But Greg, over to you.

Greg Givens — Executive Vice President & Chief Operating Officer

Yeah. So yeah, we’re in our seventh year of surfactants in the Permian. And so we’ve learned a lot over that time. We’ve learned where they work best, what concentrations work best, as Brendan said earlier, which chemicals are most effective for the lowest cost. And so we’ve really advanced our learnings there. We’re still in the early innings up in the Montney. The team does a great job, though of sharing learnings cross-border and cross assets. So we’re absolutely looking at things up there, and we’ve done some of the rock work, and we’ve done a few trials so far.

And so we’re just — I would position it more as we’re just getting started up there, but the whole toolbox is available to us as we see that working as well as we see higher completion intensity, stacking and spacing optimizations. All the things that we do in the Permian, we do the same in the Montney. And so we’ll share those learnings cross-border, but maybe just a little earlier stage in the Montney on surfactants. And it will be a slightly different setup just because of the pressure regime downhole and the rock fabric, it’s just a different reservoir, but we’ll work to see if we can make the same kind of improvements there that we’ve seen in the Permian.

Betty Jiang

Great. Sounds good. Thank you.

Brendan McCracken — President & Chief Executive Officer

Thanks, Betty.

Operator

Thank you. The next question comes from Phillip Jungwirth at BMO Capital Markets. Please go ahead.

Phillip Jungwirth

Yeah, thanks. Good morning. Just with some of the industry news today, can you talk about how you see the prospectivity for the Barnett, Woodford across your Midland acreage? And where that might be across North, South and any plans to test this?

Brendan McCracken — President & Chief Executive Officer

Yeah, I’ll turn this to Greg. But really pleased with the job the team has done here to assemble a position in the Barnett. But Greg, over to you.

Greg Givens — Executive Vice President & Chief Operating Officer

Yeah. So we’ve been very interested in the Barnett and have been watching it for some time. I do think this is one of those plays that we’re wise to learn from our peers and see what — the two things that are going on with the Barnett, it’s a deeper zone. So it’s got more pressure, and it looks like it’s got good productivity, but it’s also got higher costs. So we’re watching as some of our peers are derisking the cost side as well as derisking the well performance. We do have a meaningful Barnett position.

We’ve got Barnett rights on about half of our acreage position in the Permian, so around 100,000 acres. We’ll look to test that this year with our first well. So we’ll get some information of our own, but we’re also going to watch and I think be prudent on how much we lean into the Barnett. It’s a deeper horizon that’s separate from our cube, so that resource is still going to be there later. It’s not going to be impacted by the shallow production. So I think this is one where we have time to be a little more patient, but also have the ability to be a fast follower and go execute on that 100,000 acres if we choose to do so.

Phillip Jungwirth

Okay. Great. And then can you talk about what you’ve seen with LNG Canada ramping up the second train starting up just as it relates to the AECO market and Ovintiv supplying that versus maybe incremental equity volumes for the partners and more hypothetical, but would changes in ownership across the facility have any implications for Ovintiv or open up any strategic partnership or marketing opportunities?

Brendan McCracken — President & Chief Executive Officer

Yeah. So I think — so we are pleased in recent weeks to see that facility ramp up to essentially full capacity, which is kind of really the first time since the start-up that it’s been at that level. So it’s been a slow grind upwards with a bit of ups and downs along the way, as I’m sure you followed. So I think our caution on AECO remains the total takeaway from LNG Canada, while it’s great to see it in recent time up to that level. It’s still relatively small relative to the total productivity potential of the basin, and we’ve seen the sort of behind pipe volumes, if you will, able to fulfill that takeaway.

So still cautious AECO, still strong believers in diversifying our Canadian gas portfolio into alternate markets, which is, I think, kind of part B of your question there. So yeah, we continue to be interested in building out a diverse portfolio of markets for our downstream gas and further LNG exposure is going to probably be part of that over time. We’ve now added that to our portfolio, and we’re excited to have those positions in place. But I would expect over time, we will probably grow that exposure.

Phillip Jungwirth

Thanks.

Brendan McCracken — President & Chief Executive Officer

Yeah, thank you.

Operator

Thank you. The next question comes from Kevin MacCurdy with Pickering Energy Partners. Please go ahead.

Kevin MacCurdy — Analyst, Pickering Energy Partners

Hey, good morning. You guys have laid out a solid maintenance program with a big buyback for this year. But I wanted to revisit the growth question. You’ve talked about the potential to grow the Montney by 5% a year. And now that the portfolio transformation is about to be complete, debt is being reduced and you have oil in the mid-60s, how does that growth opportunity stack up in your capital allocation framework and what could change that rank?

Brendan McCracken — President & Chief Executive Officer

Yeah, no, appreciate it, Kevin. I think the two things that we’ve talked about with respect to growth are still very much in place. So the two gates, if you will, are — do we see a fundamental call for incremental barrels or BTUs? And again, we don’t see that today. The market’s not begging for companies like ours to bring more volumes into the market. So that’s kind of gate number one. And then gate number two is can we create more cash flow per share growth out of share buybacks or out of incremental rigs? And today, we see that equation tilted towards the buyback.

So we get a better cash flow per share outcome across a range of commodity price assumptions going forward and share price assumptions going forward. We expect we get a better cash flow per share outcome out of buying the shares. So the combination of both of those two gates today are telling us to stay in maintenance mode. But I appreciate your question because it surfaces the other aspect of the portfolio transformation that’s important here. So not only have we added tremendous inventory duration and focus the portfolio, we’ve also unlocked growth potential. And at some point in the future, those two gates will call for growth, and we’ve now created the capability to do that very efficiently at high return for our investors.

Kevin MacCurdy — Analyst, Pickering Energy Partners

I’ll leave it there. Appreciate the answer. Thanks.

Brendan McCracken — President & Chief Executive Officer

Yeah. Thanks, Kevin.

Operator

Thank you. The next question comes from Dennis Fong with CIBC World Markets. Please go ahead.

Dennis Fong — Analyst, CIBC World Markets

Hi, good morning and thanks for taking my questions. My first one relates towards inventory to some degree. It’s clear that you’ve done a lot of work around the ground game to add low-cost, high-quality premium inventory. Can you kind of talk towards how that helps you kind of either gain comfort with existing depth as well as how that may influence allocating capital both North and South of the border, which from what looks kind of like from a well count perspective or a TIL perspective almost a balanced program North and South.

Brendan McCracken — President & Chief Executive Officer

Yeah. You got it, Dennis. So that ground game has been really effective for us. Obviously, a lot of focus on the larger transactions, but the ground game has been grinding away very efficiently. And you think about where we’ve arrived at here, we’ve put the transaction risk of having to build inventory duration behind us. And now we can rely on that ground game, which is very efficient, low-cost way to sustain our inventory duration. And it just is sort of funded within our framework, within the balance sheet that we’ve got today.

So we can just sort of put that in and let it opportunistically pick away as we go along here and sustain the inventory depth that we’ve created. So we like that feature, and we’re really proud of the team for how it’s been able to do that over time. As far as the capital allocation between the assets today, we’re really just holding both of those assets at that flat production level. And the outcome is, like you said, a relatively balanced TILs, North and South. But it’s really more designed to hold the production flat.

Dennis Fong — Analyst, CIBC World Markets

Great. Appreciate that. Shifting on to innovation. There’s obviously a lot of questions today focused on obviously use of surfactant, and obviously, your teams have done a very good job in terms of applying leading-edge technology on improving operations. I’m just curious, has there been anything that you guys have learned potentially from the NuVista teams and operations that they were doing or techniques that they were running that you believe could be applicable to your existing Montney base and/or even the Permian?

Brendan McCracken — President & Chief Executive Officer

Yeah, no, we love that question, Dennis. And really, this is our — one of our mantras here is the only infinite rate of return we can generate is by learning from somebody else’s capital. And what better way to do that than in an integration where you have full transparency and data and everything, but I’ll put that to Greg because there are several things that we’ve been excited about from the NuVista team.

Greg Givens — Executive Vice President & Chief Operating Officer

Yeah. We were really pleased with the NuVista transaction. Not only did we get some great assets, we’ve also got a number of really quality individuals that came over with the transaction and brought over some really good ideas. So out in the field, I think they’ve done a really good job on some of their gas lift designs and how they’ve optimized their gas lift techniques in the field. So we’re already working with them on how do we take some of those ideas and then using more broadly across our portfolio, incorporating with our operations control center and really upping our game a little bit there on the gas lift, which will have some application in the Permian, but definitely will have application across the Montney.

Another place that we’ve talked with them a lot about is on landing zones, on the very precise, not which interval in the Montney, but to the meter, to the foot where you’re going to land the wells and they’ve got some really good ideas that they’ve been able to execute on some different landing zones that have allowed them to drill wells a little faster than we have in some cases. So we’re implementing that into our program, and we think that’s going to help us even improve quicker in Canada than we have been so far. So our teams are doing a really good job, but we’re always open to learning from others.

We try to approach competitor intelligence or integrations with — what can you teach us? Not what can we tell you we know. And so far, we’re learning some from them, and it’s going really well. So we’re really pleased with that.

Brendan McCracken — President & Chief Executive Officer

Thanks, Dennis.

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 — Vice President, Investor Relations and Planning

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

Operator

[Operator Closing Remarks]