Ovintiv (OVV) Q4 2025 Earnings Call Transcript

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Date

Feb. 24, 2026, 10 a.m. ET

Call participants

• President & CEO — Brendan McCracken
• Chief Financial Officer — Corey [Surname not provided]
• Chief Operating Officer — Gregory Dean Givens
• Head of Investor Relations — Jason Verhaest
• Operator

Takeaways

• Portfolio transformation -- Ovintiv (NYSE:OVV) completed the NuVista acquisition and agreed to sell its Anadarko assets, resulting in a focused portfolio concentrated in the Permian and Montney plays.
• Net debt target -- Net debt is expected to be approximately $3.6 billion after the Anadarko sale, enabling Ovintiv to achieve its debt reduction goal and strengthen its balance sheet.
• Shareholder returns framework -- The new framework targets returning at least 75% of free cash flow to shareholders in 2026, with a longer-term range of 50%-100% to manage commodity price volatility.
• Share buyback program -- The Board authorized a $3 billion share buyback, to be commenced immediately, with 2026 buybacks determined by full-year free cash flow to compensate for a planned Q1 pause.
• 2025 cash flow -- Corey's remarks cited total cash flow of $3.8 billion and free cash flow exceeding $1.6 billion; more than $600 million was directly returned to shareholders.
• Oil and condensate production -- Fourth-quarter average oil and condensate volumes reached 209,000 barrels per day, at the upper end of guidance, with capital investment of $465 million.
• Per-unit costs -- All per-unit cost items matched or beat guidance, contributing to a fourth-quarter cash flow per share of $3.81, which was approximately 10% above consensus estimates.
• Production and capex guidance -- 2026 plans include one quarter of Anadarko operations, with targeted oil and condensate output of 209,000 barrels per day, over 2 Bcf/d of natural gas, and 620,000 to 645,000 BOE per day at a capital expenditure of about $2.3 billion.
• Permian drilling performance -- Average completed feet per day in 2025 improved to 4,250, up more than 10% year over year; 2025 drilling speed again surpassed 2,000 feet per day, with a pacesetter well exceeding 3,000 feet daily.
• Permian surfactant program -- Surfactants deployed in about 300 wells since 2019 generated a 9% uplift in oil productivity versus comparable control wells; roughly 75% of Midland Basin completions in 2025 used surfactants, with similar proportions planned for 2026.
• Permian well costs -- 2026 expected drilling and completion cost is below $600 per foot, about $25 per foot less than in 2025, supported by cycle time improvements and surfactant use.
• Gas marketing -- About 55% of Permian gas to be priced at Gulf Coast rather than Waha, with 2025 unhedged Permian gas price realization at $1.55 per Mcf, or 179% of Waha pricing.
• Montney operations -- 2026 drilling and completion costs targeted below $500 per foot, $25 per foot below 2025, with half of completions to use domestically sourced sand.
• Integration synergies -- $1 million per-well cost savings targeted in NuVista assets integration; similar $1.5 million per-well savings realized during Paramount integration, shortening drilling cycle time by 14 days.
• High-density pad results -- The 15-16 pad in the Montney used 14 wells per section, unlocking about 130 upside locations for future inventory.
• Montney production guidance -- Full-year Montney oil and condensate output guided at 83,000 to 87,000 barrels per day and 1.75 to 1.85 Bcf per day of natural gas; plant turnarounds in Q2 expected to push output toward the lower end of guidance.
• Q1 2026 production and capital -- Projected first-quarter production of about 170,000 BOE per day (including 223,000 barrels per day of oil and condensate) and capital spend of $625 million, with seasonal cold weather impacts totaling 3,000 to 4,000 BOE per day.
• Long-term debt structure -- After debt repayments post-Anadarko sale, no long-term maturities remain before 2030; anticipated annualized interest savings total $40 million from retiring 2028 notes, in addition to $25 million saved from 2026 notes paid earlier.

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Risks

• Planned Montney plant turnarounds will coincide in Q2, with five facilities undergoing maintenance at the same time, leading management to guide Montney production to the lower end of the 83,000-87,000 barrels per day range.

Summary

Ovintiv (NYSE:OVV) announced the completion of its multi-year portfolio transition, now focused on the Permian and Montney basins, backed by the finalized NuVista acquisition and pending Anadarko divestiture. Management's revised shareholder return framework raises 2026 cash returns to at least 75% of free cash flow and introduces a $3 billion buyback program, citing perceived undervaluation of equity and debt target attainment. New operational metrics include cycle time improvements, reduced capital intensity, and stronger integration synergies, resulting in sustained production guidance despite strategic asset sales. Near-term challenges arise from coinciding Montney plant maintenance in Q2, but Ovintiv projects margin improvements driven by lower taxes and interest costs. The groundwork has been laid for additional synergies in infrastructure and organizational design, optimizing performance as the business transitions to ongoing stability.

• Management emphasized that full-cycle inventory quality and balance sheet strength now allow allocation of free cash flow primarily to shareholder returns.
• “Approximately 80% of the remaining sub-$50 breakeven oil locations in North America are located in [Permian and Montney],” supporting competitive advantages in these core basins.
• Leadership stated, “The portfolio transition here is complete,” indicating a pause on further major M&A actions in the near term.
• Montney infrastructure optimization and further cost synergies are being targeted as portfolio integration continues, with near-term well cost savings already incorporated into 2026 guidance.
• Integration of NuVista introduced technical learnings, including gas lift design improvements and refinements to well landing zones, now being adopted across both Montney and Permian assets.

Industry glossary

• BOE: Barrels of oil equivalent, a standardized unit combining oil, natural gas, and NGL volumes based on energy content.
• Cube development: Simultaneous drilling and completion of multiple stacked reservoir intervals within the same geographic area to optimize resource recovery and minimize well interference.
• Frac spread: Set of hydraulic fracturing equipment and crews used to stimulate oil and gas wells during completions.
• Turn-in-line (TIL): The point when a well is completed and connected to production facilities, beginning regular output.
• Waha: A key natural gas price hub in West Texas, known for occasional price discounts versus Gulf Coast benchmarks.
• Netback: The net revenue per barrel of oil equivalent after subtracting royalties, production, transportation, and marketing costs.

Full Conference Call Transcript

Brendan McCracken: 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 Inc. 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 have been guided by a very simple formula.

Superior and durable returns will accrue to the company that builds 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 have increased our Permian and Montney drilling inventory by more than 3,200 locations at an average cost of $1,400,000 per net 10,000-foot location, 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 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, can access premium priced 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 $3,600,000,000. 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 $3,600,000,000. If you will 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 $40,000,000 of annualized interest savings from the repayment of the 2028 notes. This is in addition to the $25,000,000 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 sale 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 procyclical 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 $3,000,000,000. I will now turn the call over to Corey to discuss our year end results and 2026 guidance.

Corey: Thanks, Brendan. Our 2025 results demonstrate another year of execution excellence and strong financial performance. Our full year cash flow was $3,800,000,000. We generated free cash flow of more than $1,600,000,000, of which over $600,000,000 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 $2,200,000,000 of capital. Throughout the course of the year, we lowered our capital by $50,000,000 and produced an additional 10,000 BOE per day of total volumes.

Importantly, we also continued to make progress on debt reduction, ending the year with less than $5,200,000,000 of net debt, a decrease of more than $240,000,000.

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 $465,000,000 came in at the midpoint of our guidance. We also matched 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 $508,000,000.

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 are 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 2 Bcf a day of natural gas, and total production volumes of 620,000 to 645,000 BOE per day, for about $2,300,000,000 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 BOE per day, and the timing of the NuVista acquisition closing reduced those volumes by about 10,000 BOE per day.

We expect to see margin improvement in 2026 driven by lower 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 marketing in both plays, which enhances our netbacks. In the first quarter, we expect production to average approximately 170,000 BOE 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 or 4,000 BOE per day of cold weather impacts that we experienced across the U.S. assets in January.

Our capital spend will also be the highest in the first quarter at about $625,000,000, largely due to $50,000,000 of capital allocated to the Anadarko and some drilling activity in the Montney that we inherited from NuVista. I will now turn the call over to Greg, who will speak to our operational highlights.

Gregory Dean Givens: Thanks, Corey. Let us dig into each of our two asset-level 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 operation. Ovintiv Inc. 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 Inc. 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 type curve improvement over that period of time, and one of the bigger factors has been our use of surfactants in our completion designs. We have 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-treated wells, we see a 9% improvement in oil productivity. We believe surfactants account for roughly half of the type curve improvement we have 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 these 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 have 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 pump is optimized in real time using proprietary algorithms leveraging our vast private Permian dataset. This also allows us to make real-time decisions which improve well recovery and reduce cost, 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 pacesetter well was over 3,000 feet per day, so we will look to continue improving on what we believe are basin-leading results. These cycle time improvements are driving lower well costs.

Our 2026 expected drilling and completion cost is among the best in the industry, 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 remains unchanged in 2026. This year, we plan to run a level-loaded 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, important to note that we now have about 150,000,000 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 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 $1,000,000 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 could not be more pleased with how those assets have performed. We quickly achieved our well cost savings target of $1,500,000 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 15-16 pad, we added a third bench and increased density to 14 wells per section, and we are 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 and speed, 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 to 87,000 barrels per day and 1.75 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 the low cost, high productivity nature of the wells has meant we have consistently been able to generate highly competitive economics from the play throughout the commodity price cycle. I will now turn the call back to Brendan.

Brendan McCracken: Thanks, Greg. Over the last few years, we have 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 have been very intentional about building a high quality business. We have 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 have reached a new period of stability, and we are excited to unlock the full value of what we have built. This concludes our prepared remarks. Operator, we are now ready to turn the line back for questions.

Operator: Thank you. By pressing star 1. 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: Yes. 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 are 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: 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 $3,600,000,000 of debt. And so that is really the reason for shifting to the upper end of the range this year. And then longer term, we have set a wider range. And, really, the thinking here is, you know, we want this framework to be durable through the 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, you know, 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, you know, below the mid-cycle level, that could push us to the higher end of the range where we are likely to see more value in the equity.

So that is the only thinking behind the longer-term 50% to 100% range, and we will have the ability to flex around that. But, you know, 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, you know, very interested in the surfactant program and perhaps were 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, which looks to be driving some productivity gains versus control wells. And it looks like you are using surfactants more than 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: Yeah. No. I love the question, Arun. And, yeah, there is a lot going on in the company today. So glad you dug in on that surfactant piece. I will maybe just set up a couple comments here and then kick it over to Greg on the details. But, you know, this is just another example of the stacked innovation that we have been talking about. And, you know, really, for a few years now, we have been emphasizing three key features in our completion design that we think are adding value, adding to our type curves. And we have been calling it fluid chemistry.

We were kind of deliberately trying to keep it quiet on exactly what we were doing since we felt like we had kind of gotten out ahead of others in this space, and that is what you are seeing us show off today with 300 results already. That is, you know, really helped to push us to the top of the leaderboard on Permian productivity. So that is kind of a bit of the background, but I will kick it to Greg here to talk about some of the specifics.

Gregory Dean Givens: Yeah. Thanks, Brendan. And thanks, Arun, for the question. And, yes, you highlighted it correctly. We are focusing our program on the initial completions. This is something we have 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 are doing. So these surfactants that we are pumping, you know, they are liquid additives that we include in our fluid. They are designed to improve oil recovery from 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 have demonstrated over the last several years. We have been working for a number of years on this, both in the lab and in the field. We have done core testing in the labs as well as field trials to try to determine which surfactants work best and which zones.

We have 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. So far, you know, we pumped, as we said in the prepared remarks, surfactants in around 300 wells generating that 9% uplift with some field trials. But that has been a progression over time. So we started out in the early years, gained confidence, and more recently, last year, we pumped surfactants in about 75% of the completions we have pumped in the Midland Basin and saw very good results with that. We would anticipate pumping a similar amount this year in 2026.

So been very pleased with the results on our completions. We have also tested it to some degree in producing wells. We have not seen quite the effectiveness there, and so that is a very small part of the program. But the team continues to experiment with this, and we will continue going forward. But we do believe it is a very effective way to improve recovery in the near and long term from these wells, and we think it is 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. Thanks, Brendan.

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

Francis Lloyd Byrne: Hey, good morning, guys. Congrats on the transformation. I know it has 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 are just in the early stages, but if you have 9% improvement, are the costs going up as well?

Brendan McCracken: Hey, Lloyd. Yeah. So this is an interesting question. So when we first started this work several years ago, there was some really, you know, 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, you know, 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, you know, one of the things we have been fine-tuning is the amount of the surfactant that we have been pumping, but the other feature has been substituting, you know, cheaper and cheaper alternatives. So we have been a little reluctant to be specific about some of this here because we are trying to protect what we think is an advantage. But, you know, it is in the hundreds of thousands of dollars a well, is probably a good way to think about it.

Francis Lloyd Byrne: Okay. And then just as a follow-up, you have 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: Yeah. So, you know, really appreciate that, Lloyd. And, you know, with this latest transaction, what we pointed to is $100,000,000 of synergies, but we also pointed to several, you know, synergies that we did not quantify at this time. And,you know, we think those are going to show up on the infrastructure side. We saw that with the Paramount integration. And, really, now we are kind of stitching together our legacy infrastructure, the Paramount infrastructure, and then now the NuVista infrastructure. All three of those overlap, and so there is 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 is going to be some organizational synergy here too. You know, 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 have 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 will update the market on the impact of those, you know, once we get there.

Francis Lloyd Byrne: Great. Congratulations again. Thanks.

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

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

Brendan McCracken: Yeah, Neal. You got it, Neal. That is about the activity cadence going forward. It is going to be that one third, one third, one third. And just a quick comment on the driver for that. That is really an outcome of our reoccupation strategy. And folks will remember that 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, you know, a lot has been made over the last several years about the interwell effect of co-development or cube development. But there is also intercube 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 no 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 is the big driver of that piece there.

Neal Dingmann: 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. I can I assume that the development will continue to consist mostly exclusively of cube development, and if so, you know, is well spacing staying relatively the same there, or is there any changes?

Gregory Dean Givens: Yeah. Thanks for the question, Neal. Yeah. In the Permian, we continue to optimize and make small, small tweaks over time to our well spacing to account for, you know, the existing cubes or parent wells in an area. But overall, we are still using the same approach. So we complete the entire cube at the same time, come back 18 months later, and complete the offset cube, getting, you know, all of the zones at the same time at a fairly similar spacing, and that is allowing us to get very consistent results year over year. So we are not saving any, you know, lesser zones to come back later when they would be disadvantaged.

We are getting the whole cube at the same time, and that is working quite well for us. So no major changes there.

Neal Dingmann: Good to hear. Thanks, Greg.

Gregory Dean Givens: Thanks, Neal.

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

Neil Singhvi Mehta: Yes. Thanks so much. And, Brendan, congratulations on, again, this transformation over the last five years. And maybe that is 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 are at two. Are you in your sweet spots? Does that mean that, you know, there is 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 are still exploring?

Brendan McCracken: Yeah. Thanks, Neil. Yeah. The portfolio transition here is complete. So we have clearly planted our flag in the Montney and the Permian where we have competitive advantage and where we see the best resource. And we 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 Singhvi Mehta: Okay. Appreciate that. And then just a follow-up is just on the shape of both production and CapEx through the year. Guess Q1 is a little bit heavier, but that is, I am guessing that is part of that is just the pro forma portfolio. And then Q2, you have got a little bit more maintenance Montney. So could you just talk about how you are thinking about the cadence for production, quarterly cadence of production and then capital through the year?

Brendan McCracken: Yeah. Great. You nailed it exactly, Neil. So the little bit higher capital in Q1 is absolutely just the Anadarko effect, and so once we close that, that will come out and we will just run-rate out. And, you know, I think we have probably said transition or transformation the highest word count of this call so far. But one of the other pieces that we have transformed is the load-level nature of our programs, and that has been, you know, over multiple years here to shift to a fully load-level program. And, really, we have got that as a really key feature in 2026.

So we really like how we have leveled out that, and it just creates more predictable and stable business to operate within.

Neil Singhvi Mehta: Thanks, Brendan.

Brendan McCracken: Yeah. Thanks, Neil.

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

Greg M. Pardy: Yes. Thanks. Good morning. I had a really couple of technical questions. I was curious just first how much of an opportunity is there to using in-basin sand? I caught some of Greg's comments or Brendan, your comments, but I am just wondering, has that been perhaps optimized in both the Montney and the Permian?

Brendan McCracken: Yeah. Love the question, Greg. Yes. So we are really excited about the in-basin sand, excited about results that we are already delivering in the Permian, and really the evolution that is 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 stack 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, you know, maybe, Greg, if you want to give a few comments around the percentage of utilization and where we are headed there.

Gregory Dean Givens: Yeah. Thanks, Brendan. Yeah, Greg. So on the Permian side, you know, we have 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 continue to refine that process with our sandpile and our delivery systems, but that is 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 have been working with providers there to use more local domestic sand. The sources are not quite as close to the field, but there are good sand sources. And this year, we are going to have roughly 50% of our sand pumped will be domestic sand there sourced in Canada. So you eliminate that rail charge, you are able to lower cost dramatically. We have also begun testing wet sand in Canada, and it works quite well. This time of year, we joke it is a little crunchier, but it still goes downhole just the same.

And that is an evolving technology that we think we are 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 M. Pardy: Okay. Thanks for that. And then I will maybe just kind of stay with Montney now. When you kind of compare and contrast NuVista versus the Paramount acquisitions, can you, how do you look at perhaps degree of low hanging fruit, cost synergies, efficiencies and things like that? I think, Brendan, you mentioned NuVista was actually a pretty good operator. I am just curious on the two.

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

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

Gregory Dean Givens: Yeah. For sure. Yeah. I think Brendan set it up really well. It is going to be the same process on NuVista as it was on Paramount. It is 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 are going to try to accelerate things a little. And we think that is very doable. So the team is already hard at work, you know, employing the same playbook that we have used on all the last 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 Inc. You know, it is only been a few short weeks, but we have already connected all the producing wells to our operations control center so that we can optimize production and minimize downtime. We have linked the drilling rigs to our DRIVE Center, which is our optimization tool where we use AI to help optimize drilling performance, and that is going to allow us to deliver our synergies here very quickly. We have already incorporated the $1,000,000 per well of savings, the synergy savings are what you are seeing as part of the guidance. We are going to be delivering that from day one.

And so far, we have 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 last time. It will just go a little faster and hopefully be even more effective.

Brendan McCracken: Greg, that is, I said that. High density. 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 M. Pardy: Terrific. Yeah. Thanks for the rundown, and congrats on the transformation.

Brendan McCracken: Thank you, Greg.

Operator: Thank you. The next question comes from Joshua Ian Silverstein at UBS. Please go ahead.

Joshua Ian Silverstein: From a balance sheet perspective pro forma, you are now below that $4,000,000,000 long-term target that you have 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 in a debt level kind of think about free cash flow allocation? Thanks.

Brendan McCracken: Yeah. Hey, Josh. So, yeah. So we have reached that target. In fact, we are going to move past it here with the Anadarko proceeds. So, you know, really, we are not setting a new target here. If you remember, the $4,000,000,000 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, you know, 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, you know, we have had to balance that debt reduction as part of our capital allocation for a long time. We have now put ourselves into this resilient position. And at the same time, we put the inventory into a really strong and resilient position as well. So it just means we are in a place here now where we can focus on keeping the debt, you know, around this level and focus on allocating more to cash returns. So that is how we are thinking about debt level go forward.

Joshua Ian Silverstein: Got it. And then from a Montney operating perspective, I know you guys on the Paramount transaction were able to, like, 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 go and 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?

Brendan McCracken: Yeah, I will 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, you know, value-creating mindset over all three of them. But, you know, Greg, you can comment.

Gregory Dean Givens: Yeah. Thanks for the question. And so in the short term, we are really focused on, you know, getting the well cost savings at the well level, putting in our completion designs, our facilities designs, and that is going to take place over here, like, immediately over the coming months. Longer term, though, we are really excited about the opportunity to optimize infrastructure. You look at the map, it 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 is a little more time consuming to work with the midstreamers to make sure we are doing the most efficient operations there. But over time, that is something we are going to target to get our T&P down, to get the gas molecules to the most efficient plant, and to work through those things. So that is coming a little longer, but in the short term, we are really excited about the well cost savings. Longer term, we think the midstream, there is a lot of opportunity there. And that will be something we will start working on here immediately.

Joshua Ian Silverstein: Great. Thanks, guys.

Brendan McCracken: Thanks, Josh.

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

Doug Leggate: Hey, good morning, everybody. Brendan, I wonder if I could ask you about asset duration and how you define that. The portfolio repositioning has been extraordinary, as everybody has observed. But I am trying to understand, and I asked this question to Diamondback earlier 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: Yeah. We, I mean, we have not been exotic with our thinking there. We just run it off of what it takes to sustain the production, you know. And in a lot of ways, what we have been talking about, Doug, is the ability to sustain the returns that we are generating today while we do that production maintenance level. And, you know, this, again, at the risk of being too pedantic with it, this is why the reoccupation strategy and how we have approached both cube development but also program design really derisks our inventory duration over time.

And just as a refresher here, because we are designing our annual programs with that reoccupation in mind, so to come back to the 18 to 24 months after we have drilled the prior cubes, because that has 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 is going to perform because we are drilling it today. We are not saving, you know, the worst locations for, you know, a decade from now.

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

Doug Leggate: I appreciate that answer. I know it is a bit nuanced more than anything else. But forgive me for my second one, but you probably know I am going to talk about capital structure and that stuff. But I want to ask you about your philosophical view as a 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 is exactly what you are doing in 2026, if I may say so. Meaning that your stock is up 25%, ExxonMobil is up 22%, oil is above 70 for reasons we all know are not necessarily fundamental.

And this is the year you are going for a 75% of your free cash flow per share buyback. Why are you not choosing to be more discretionary in your timing?

Brendan McCracken: Yeah. I am going to try and not be, I guess, I am going to still try and be humble here, but 30% still does not get us to what we think is a reasonable valuation for the stock. So I am not trying to say that is not great, and we are pleased, obviously, with the momentum, but we still see a lot of intrinsic value in the equity today. You know, 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 are not in a commodity environment that screams, you know, really high, you know, windfall situation.

I think we are 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: All right. I wanted to take your question. Thanks so much.

Brendan McCracken: Yes. Thanks,

Operator: Thank you. The next question comes from Kelly Ackerman with Bank of America. Please go ahead.

Kelly Ackerman: My question is on the 15-16 pads, and maybe this is for Greg. Greg, wondering if you can talk about how you sequence the completions of three zones and share any details on the frac job. That third zone has been an opportunity in the area, and 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 into account this year?

Brendan McCracken: Yeah. I will turn that to Greg. Thanks, Kelly.

Gregory Dean Givens: Sorry. I had trouble turning my mic on. Yes, so I appreciate the question. And we are really, really pleased with the results there on this 15-16 pad down in CAR. So what the team has done there is, just as a reminder, you know, when we acquired the asset, our base case was 12 wells a section. We said we had upside up to 16 wells. And so this is the first pad that we really got to design end 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 is a fairly normal frac design. It was really the stacking and spacing that we leaned in on. And so far, we are really pleased. The pad has been online a little over 100 days. The lower zone is 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 CAR and employ this density design now. And that is why we have talked about 130 of the, call it, roughly 600 upside locations between the two deals. This proves up, you know, 130 of those. So the next step will be to go to other parts of CAR and test the third zone. And then we have still got work to do up in Wapiti and then in other parts of the acreage. So we will be systematic about this. One pad does not prove up all the upside.

But we will continue to execute, you know, 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 are feeling really good about it.

Kelly Ackerman: Thanks for that detail, Greg. Maybe staying with the Montney here, the second question is on the plant turnarounds 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 a turnaround is needed? And should we expect better performance from these plants, and maybe that is in yield, after this work has been completed?

Brendan McCracken: No. I appreciate the question, Kelly. And this is fairly normal operations from the midstream processing plants up in Canada. They are on schedules that every two 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 usually we know about well in advance. That is why we are talking to you now about something that is going to happen next quarter. What we are experiencing this coming quarter is we just happen to have five of them, which are all lined up at the same time.

And so, normally, we do not 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 are working with the midstreamers to try to minimize the amount of time that they are down, try to move volumes around them where we can. But right now, we do feel like there will be some impact, and that is why we are guiding to be at the lower end of that 83,000 to 87,000 barrels per day in the Montney.

But this is something that, I would say, is fairly infrequent that they all line up in the same quarter. Usually, they are more spread out over time and they are more manageable. So I do not 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 are planning for it. So that when we come back and report Q2 earnings, there is no surprises. So just trying to give you guys a heads up, but trust that we are working to try to minimize the impact as much as we can.

Kelly Ackerman: And, Greg, just to follow-up. Coming out of maintenance, could there be any increase in the performance in those plants? Maybe that is in yield after that work is done.

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

Kelly Ackerman: Thank you, Greg.

Brendan McCracken: Thanks, Kelly.

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

Phillip J. Jungwirth: Yes, 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: Yes. I will 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.

Gregory Dean Givens: Yeah. So we have been very interested in the Barnett and been watching it for some time. I do think this is one of those plays that we are wise to learn from our peers and see what the two things that are going on with the Barnett, it is a deeper zone, so it has got more pressure and looks like it has got good productivity, but it has also got higher cost. So we are 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 have got Barnett rights on about half of our acreage position in the Permian, so around 100,000 acres. We will look to test that this year with our first well. So we will get some information of our own, but we are also going to watch and I think be prudent on, you know, how much we lean into the Barnett. It is a deeper horizon that is separate from our cube, so that resource is still going to be there later. It is 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 J. Jungwirth: Okay. Great. And then can you talk about what you have seen with LNG Canada ramping up, the second train starting up, just as it relates to AECO market, you know, Ovintiv Inc. 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 Inc. or open up any strategic partnership or marketing opportunities?

Brendan McCracken: Yeah. So I think, 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 has been at that level. So it has been a slow grind upwards with a bit of ups and downs along the way, as I am sure you followed.

So I think our caution on AECO remains, you know, the total takeaway from LNG Canada, while it is great to see it, you know, in recent time up to that level, it is still, you know, relatively small relative to the total productivity potential of the basin, and we have 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, you know, further LNG exposure is going to probably be part of that over time. We have now added that to our portfolio, and we are excited to have those positions in place. But I would expect over time we will probably grow that exposure.

Phillip J. Jungwirth: Thanks.

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

Kevin MacCurdy: Hey, good morning. You guys have laid out a solid maintenance program with big buyback for this year. But I wanted to revisit the growth question. You have 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-sixties, how does that growth opportunity stack up in your capital allocation framework? And what could change that rank?

Brendan McCracken: Yeah. No. Appreciate it, Kevin. I think that is very much in place. So two things that we have talked about with respect to growth are still the two gates, if you will, are do we see a fundamental call for incremental barrels or BTUs? And, again, we do not see that today. The market is not begging for companies like ours to bring more volumes into the market. So that is 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 rates? And today, we see that equation tilted towards the buybacks.

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 is important here. So not only have we added tremendous inventory duration and focused the portfolio, we have also unlocked growth potential.

And at some point in the future, those two gates will call for growth, and we have now created the capability to do that very efficiently at high return for our investors. I will leave it there.

Kevin MacCurdy: Appreciate the answer. Thanks.

Brendan McCracken: Yeah. Thanks, Kevin.

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

Dennis Fong: Hi, good morning, and thanks for taking my questions. My first one relates towards inventory to some degree. It is clear that you have 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. Yeah.

Brendan McCracken: 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 know, you think about where we have arrived at here, we have put the transaction risk of having to build inventory duration behind us. And now we can, you know, rely on that ground game, which is a very efficient, low-cost way to sustain our inventory duration. And it just is sort of funded, you know, within our framework within the balance sheet that we have 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 created. So we like that feature and, you know, really proud of the team for how it has been able to do that over time. As far as the capital allocation between the assets today, we are really just holding both of those assets at that flat production level. And the outcome is, like you said, a relatively balanced TIL north and south. But it is really more designed to hold the production flat.

Dennis Fong: Great. Appreciate that. Shifting on to innovation, there is 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 am just curious, has there been anything that you guys have learned potentially from the NuVista team and operations that they were doing or techniques that they were running, and or even the Permian, that you believe could be applicable to your existing Montney base.

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

Gregory Dean Givens: Yeah. We were really pleased with the NuVista transaction. You know, not only did we get some great assets, we have 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 have done a really good job on some of their gas lift designs and how they have optimized their gas lift techniques in the field.

So we are already working with them on how do we take some of those ideas and then use them more broadly across our portfolio, core 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 have talked with them a lot about is on landing zone. On the very precise, not which interval in the Montney, but, you know, to the meter or to the foot where you are going to land the wells. And they have got some really good ideas.

They have 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 are implementing that into our program, and we think that is 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 are always open to learning from others. We approach competitor intelligence or integrations with what can you teach us, not what can we tell you we know. And so far, we are learning some from them, and it is going really well. So we are really pleased with that. Thanks, Dennis.

Operator: Thank you. At this time, we have completed the question and answer session. I will 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 call for today. We thank you for participating, and we ask that you please disconnect your lines.

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