Ovintiv (OVV) Q1 2026 Earnings Call Transcript

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DATE

Tuesday, May 12, 2026 at 10:00 a.m. ET

CALL PARTICIPANTS

• President & Chief Executive Officer — Brendan Michael McCracken
• Executive Vice President & Chief Financial Officer — Corey Douglas Code
• Executive Vice President & Chief Operating Officer — Gregory Dean Givens

TAKEAWAYS

• Permian and Montney drilling inventory -- Expanded by more than 3,200 locations since 2023, without shareholder dilution and while increasing return on capital employed (ROCE) and reducing debt.
• Shareholder returns since 2021 -- Totaled $3.7 billion, with $2.4 billion from buybacks and $1.3 billion from base dividends.
• Free cash flow return framework -- Revised to distribute 50%-100% of free cash flow to shareholders; for 2026, at least 75% initially planned, with range shifting to 50%-75% allocation if oil prices remain elevated.
• Net debt as of April 30 -- Under $3.3 billion, or less than 0.8x leverage; no long-term maturities before 2030.
• Annualized interest savings -- Over $80 million expected from year-to-date debt reduction, including repayment of 2026 and 2028 notes and credit facility balance.
• Liquidity -- Maintained at $4 billion.
• Cash flow per share -- $4.62, exceeding consensus by approximately 6%.
• Free cash flow for the quarter -- $634 million.
• Oil and condensate production -- Averaged about 225,000 barrels per day, at the high end of guidance.
• Capital investment -- $605 million, at the low end of guidance; capital spend for next quarter guided to approximately $575 million.
• After-tax non-cash impairment -- $1.2 billion ceiling test impairment due to weaker first-quarter oil prices affecting SEC trailing price; management does not expect further impairments at current strip pricing.
• Montney first quarter well productivity -- Tracking above 2026 type curve, with 85,000 barrels per day achieved in first month post-NuVista acquisition.
• Montney gas price realization -- 175% of AECO; company exposed to AECO on less than 20% of 2026 Canadian gas volumes.
• JKM-linked contract -- 100 million cubic feet per day initiated during the quarter; management projects $60 million annualized value at current strip pricing.
• NuVista integration -- $1 million per well cost savings already achieved; on track for targeted $100 million in annualized cost synergies.
• Permian oil and condensate volumes -- Averaged 126,000 barrels per day, with recent wells exceeding 2026 type curve projections.
• Permian surfactant initiative -- Application yields 9% oil productivity uplift compared to untreated wells; in 2026, almost all Permian wells will include surfactant treatment at $100,000 per well.
• Permian oil productivity per foot -- Greater than 10% improvement since 2023; compared to 2% annual decline in broader basin.
• Well cost metrics -- Permian wells below $600 per foot and Montney wells below $500 per foot.
• Canadian operations royalties -- Higher royalty rates due to elevated oil prices are reducing reported net volumes, but revenue benefits from price more than offset lost volumes.
• US cash taxes -- Minimal in 2026 and expected similar in 2027 based on current outlook.
• Inventory replacement -- Year-to-date 2026 inventory already fully replaced by density conversion in Montney and Permian Barnett activity.

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RISKS

• Corey Douglas Code reported, We recorded a $1.2 billion after-tax non cash ceiling test impairment that resulted in a loss in the quarter. explicitly tied to weaker oil prices in the first quarter driving down SEC trailing price.
• Management noted that higher Canadian royalties from elevated oil and condensate prices are currently reducing reported net production volumes, which may impact near-term volume metrics until price normalization or royalty structures change.
• Guidance indicates that second-quarter Montney production will be at the low end of the full-year range due to royalty impacts and planned plant turnarounds.

SUMMARY

Management highlighted accelerated debt reduction and strengthened liquidity following the recent Anadarko asset sale, with net leverage now below 0.8x and no significant maturities until 2030. The company revised its shareholder return policy, stressing flexible allocation of 50%-100% of free cash flow to dividends and buybacks, with an emphasis on adapting to commodity price changes. Recent operational updates include the seamless integration of NuVista, achievement of planned cost synergies, above-type-curve well productivity in both Montney and Permian, and sustained capital efficiency improvements. The quarterly $1.2 billion non-cash impairment, although tied to first-quarter oil prices, was described by management as a function of accounting rules and not expected to recur at current strip prices.

• Executives cited competitive advantages from stacked innovation referencing proprietary surfactant usage and AI-enabled operational models as key contributors to enhanced capital efficiency and type curve outperformance across core assets.
• Management explained the impact of Canada’s sliding-scale royalty regimen, noting that while higher royalties reduce net reported volumes, associated price premiums more than compensate in actual revenues.
• Scholarly use of JKM-linked gas pricing and strategic physical sales out of the AECO basin enabled realized gas prices at 175% of regional benchmarks and limited exposure to AECO to below 20% of Canadian volumes.
• Inventory depth was reinforced, with year-to-date additions through density conversion allowing both Montney and Permian positions to sustain 2026 drilling and production plans.

INDUSTRY GLOSSARY

• BOE: Barrel of oil equivalent, a standard unit combining oil, gas, and natural gas liquids for production measurement.
• Type curve: A predictive production profile representing expected well performance over time based on historical data.
• JKM: Japan Korea Marker, a price reference for liquefied natural gas (LNG) in Northeast Asia, used by Ovintiv for indexed gas sales.
• Simul frac: A simultaneous hydraulic fracturing technique improving operational efficiency by stimulating multiple wells at once.
• D&C: Drilling and Completion, representing the combined cost of drilling and bringing wells into production.
• AECO: Alberta Energy Company, the main natural gas price hub in Alberta, Canada.

Full Conference Call Transcript

Brendan Michael McCracken: Thanks, Jason. Good morning, everybody, and thank you for joining us. We believe the strategic steps for an E&P company to generate differentiated value creation will be to build a portfolio with best in class assets and inventory depth create a competitive advantage with stacked innovation and execution, demonstrate a proven track record of capital allocation, to deliver superior and durable returns, and combine all of that with a clean balance sheet. We are very excited to have put Ovintiv into the valuable position of delivering on all fronts. Since 2023, we have increased our Permian and Montney drilling inventory by more than 3.2 thousand locations. This inventory like expansion has been unmatched by our peers.

And leaves us with 1 of the most valuable inventory positions in the industry, We did it without diluting our shareholders, and while increasing ROCE and substantially reducing debt. And all along, our team has continued to build on their track record of operational and commercial excellence. The evidence of which is observable in public data. We make the highest productivity oil wells in the Midland Basin and in the Montney. And we do that as the undisputed cost leader in the Montney and among the top 2 lowest cost operators in the Midland Basin.

We have also boosted profitability by strategically marketing our volumes to deliver high realized prices lowered our cash costs, and reduced our interest expense and overhead. I am extremely proud of our team. They have shown tremendous resolve to build our business into a leading E&P. We are pleased to see the value of what we have built start to become recognized in the market, and we are excited because there is still a lot of room to run. We have had a productive start to the year, with the successful integration of the recently acquired NuVista assets the sale of our Anadarko assets, and the significant deleveraging of our balance sheet.

We accomplished all this while maintaining our focus on execution excellence, and delivering another strong quarter of operational and financial results. We believe stability has real value for our shareholders. We have fundamentally derisked our business and positioned ourselves to deliver durable returns for many years to come. Since the inception of our shareholder return framework in 2021, we have returned $3.7 billion to our shareholders. Through $2.4 billion of share buybacks and $1.3 billion of base dividends, In early March, we introduced the next logical progression of our framework. Designed to deliver substantial value to our shareholders while allowing greater flexibility. We committed to returning 50% to 100% of our free cash flow via dividends and share buybacks.

In 2026, we began the year planning to allocate at least 75% of our free cash flow to shareholder returns. The market has shifted dramatically since then with substantially higher oil prices than we expected. Even with our shares up strongly year to date, we continue to see a substantial gap between our share price and the intrinsic value of our business at mid cycle prices. That said, with the higher prices and higher free cash flow, we believe it makes sense to avoid over indexing on procyclical buybacks. We also believe it makes sense to take the opportunity to further accelerate net debt reduction.

So if oil prices continue to stay elevated, we do, we would expect to be in the 50% to 75% range. But even then, we will still allocate more absolute dollars to share buybacks than we had anticipated at the March: If oil prices retreat, we will have capacity to be opportunistic with incremental buybacks. And we would expect to be back into the 75% or above range in that scenario. Again, regardless of price movements from here, our returns to shareholders this year are now anticipated to exceed our original plan on an absolute dollar basis. I will now turn the call over to Corey to discuss our financial results.

Corey Douglas Code: In addition to our best in class asset portfolio, our balance sheet is now stronger than it has been in a decade. With the proceeds from the Anadarko sale, we were able to significantly reduce debt And as of April 30, our net debt was less than $3.3 billion or less than 0.8x leverage. Our remaining long term debt profile has no maturities before 2030. We expect to realize over $80 million of annualized interest savings from the debt we have repaid since the start of the year. This includes the repayment of the 2026 and 2028 notes as well as the balance on our credit facility.

Also have significant liquidity of $4 billion which enhances our resiliency and allows us to be flexible and opportunistic through the commodity cycle. We remain committed to our investment grade credit rating, and our recent transactions were viewed positive by the rating agencies. Our capital structure has been rightsized, Our leverage compares favorably to our peers, and going forward, we are operating from a position of strength. Our first quarter results demonstrate our continued focus on execution excellence, and strong financial performance. Our cash flow per share at $4.62 beat consensus estimates by about 6% and our free cash flow totaled $634 million.

We delivered volumes at the high end of our guidance ranges for each product, including oil and condensate production of approximately 225 thousand barrels per day. Our capital investment of $605 million came in at the low end of our guidance range as did our total per unit costs. We recorded a $1.2 billion after-tax non cash ceiling test impairment that resulted in a loss in the quarter. The impairment was driven by weaker oil prices in the first quarter bringing down the SEC 12-month trailing price. At current strip pricing, we do not expect to incur further impairments. Maximizing capital efficiency and free cash flow generation is a top priority this year.

As Brendan noted, the impacts of recent global events have increased near term pricing, However, the impact on the fundamental supply and demand dynamics remain unclear. Our portfolio now has significant duration and capability to grow production, However, we believe it is still prudent to maintain our stay flat program with level loaded activity in both the Permian and Montney, and that higher oil prices accrete to free cash flow. We are not currently seeing significant inflationary pressure on our 2020 capital program, outside of higher diesel costs. For the rest of the year, we expect to largely offset any additional cost inflation with operational efficiencies. As such, our capital guidance remains unchanged.

Despite the higher royalty rates resulting from higher oil and condensate prices in our Canadian operations, which Gregory will touch on more, we are maintaining our full year production guidance. Including 205 thousand to 212 thousand barrels per day of oil and condensate Strong performance in both the Permian and Montney is expected to offset volumes lost to higher royalties. In the second quarter, we expect production to average 623 thousand BOEs per day, including about 203 thousand barrels per day of oil and condensate. And our capital spend is expected to come in at around $575 million Activity cadence in both assets is expected be fairly ratable for the rest of the year.

I will now turn the call over to Gregory, who will speak to our operational highlights.

Gregory Dean Givens: I am really proud of the efforts made by our operating teams this quarter. Through the integration of the NuVista assets and the sale process for the Anadarko, they never lost focus on safety and efficient execution. Our team is committed to continually improving our capital efficiency and our outstanding operational performance through the first quarter gives us confidence in what we can achieve through the rest of the year. In the Montney, our first quarter well productivity was very strong and is tracking above our 2026 type curve. We hit our 85 thousand-barrel-per-day target in the first month after closing the acquisition. And we have been very pleased with the results across our acreage.

With the new Vista assets now fully integrated into our Montney operations, we are focused on running a load-level program and offsetting the impact of higher royalty rates. The sliding scale royalty structure is a unique aspect of shale development in Canada. As the name suggests, the percentage royalty that we pay slides up and down based on the prevailing commodity prices. So while gross volumes are unchanged, higher royalty rates mean our reported net volumes are reduced. On slide 10, we have provided a simplified illustration of the production and revenue impacts across a range of oil prices.

The key takeaway here is that although higher royalties result in lower net volumes, we are benefiting from higher prices where it counts. In revenue. This is a good problem to have. If condensate prices were to average $90 per barrel for the year, we would see a 5 thousand-barrel-per-day increase and a 40% increase in revenues. Although we do not like losing the volumes, this is a trade off we are willing to make. It is also worth noting condensate prices would have to reach approximately $135 per barrel before royalties would be in line with the rates paid south of the border. Which are around 20% to 25% regardless of commodity prices.

Due to royalty impacts and planned plant turnarounds, Montney production in the second quarter is expected to be at the low end of our full year guidance range. While these turnarounds and royalty changes put pressure on our reported volumes, we continue to be very pleased with our well performance from both our legacy and the new Vista asset. Our 15 to 16 well increased density test continues to meet or exceed our expectations, and we plan to test additional upside locations later this year. Without the larger royalty take due to higher commodity prices, our total company oil and condensate volumes would be trending toward the high end of the guidance range for the year.

Although the economics of our Montney wells are driven by it is important to note that our natural gas price diversification strategy continues to yield attractive results. In the first quarter, our Montney gas price realization was 175% of AECO. We continue to look for opportunities to secure both physical sales out of the basin and financial arrangements to price our gas away from AECO. We are exposed to AECO pricing on less than 20% of our 26 Canadian gas volumes. We also have a JKM linked contract for 100 million cubic feet per day that began during the quarter. That essentially is in the money when AECO trades at less than 20% of JKM.

The cash flow contribution from the arrangement was minimal in the first quarter, but at current strip pricing for the remainder of the year, it would be worth roughly $60 million Overall, our Montney asset is performing very well. We are maintaining a repeatable program type curve, and despite some royalty noise, the program is delivering fantastic results. Our team hit the ground running on day 1 of taking ownership of the NuVista assets, and they have not looked back. We spot our first pad on the NuVista acreage, the Wapiti 6-of-2, just 2 days after closing the deal. And are already achieving our cost target of $1 million in per well savings.

This brings the wells on the NuVista acreage in line with our existing Montney cost structure and sets us up to achieve the $100 million in annualized cost synergies that we promised with the transaction. We are delivering faster cycle times, extending the lateral length on wells that were otherwise constrained by lease lines, savings on completions through the use of cheaper domestic sand, and reducing wellsite facility cost by half compared to NuVista's design. We have also fully integrated the acquired producing wells with our operations control center. This allows us to remotely operate the wells and apply the same digital workflows used across our Montney operations. The result is minimized downtime and lower production cost.

We also see the potential for significant future savings from things like the ability to optimize our development plans, given more available processing capacity. The opportunity to further optimize our base production with more integrated infrastructure. I am very proud of the team and the efforts they have made to integrate the new assets into our portfolio. Our Permian team continues their track record of outperformance in the first quarter. With average oil and condensate volumes of 126 thousand barrels per day our most recent wells are exceeding the 2026 type curve. These results continue to support durable return generation across our 12 to 15 years of premium inventory in the play.

We take great pride in our development approach and our ability to stack multiple innovations to create industry leading results. Which defy the broader US shale trend of well performance degradation. As a result, we are consistently 1 of highest productivity, lowest cost operators in the Permian. Last quarter, we talked about the productivity uplift we have observed stacking innovations, like surfactants in our completion designs. We pump them in over 300 Permian wells since 2019 so our dataset is robust. Compared to a similar group of nonsurfactant 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.

At a cost of only about $100 thousand per well, these custom chemical additives are highly economic. But surfactants are only a part of the story. There are several other factors that have contributed to our improvement in well productivity, including our cube development and reoccupation approaches, stage architecture, as well as the use of AI in our operations. Trained on our proprietary dataset. The result has been greater than 10% improvement in our Permian oil productivity per foot since 2023. And this is while the broader basin is fighting a 2% annual decline.

In fact, using public data from INBRIS, you can see that in 2025, our Midland Basin peers were delivering average well productivity in line with our 2023 results. While our 2025 wells continue to perform significantly better. A recent Jefferies report highlighted our repeated annual improvements in type curve performance, and ranked Ovintiv's oil productivity per well as the highest in the basin. We said this for a while now. But we continue to see our culture of innovation as a real competitive advantage. it is not something you can buy, something that must be cultivated over time. And we are seeing it deliver tangible results. I will now turn the call back to Brendan.

Brendan Michael McCracken: Thanks, Gregory. I would like to take a moment to recognize our team. For the safe and strong first quarter results they achieved. And acknowledge their focus and drive to make our business more profitable for our shareholders. We delivered another strong quarter meeting or beating our targets and delivering cash flow per share and free cash flow per share above consensus estimates. Our integration of the NuVista assets is complete. And we are generating free cash flow well in excess of our expectations at the start of the year. Our track record of skating to where the puck is going is proving to be very valuable for our shareholders.

Over the last few years, we have worked hard to high grade and focus our portfolio. Build extensive inventory depth, drive capital efficiency, and reduce our leverage. Along the way, we demonstrated that we are disciplined stewards of our shareholders' capital. Now we are entering a period of stability where we can focus on maximizing the profitability and efficiency of our business. We are excited to unlock the full value of what we have built. This concludes our prepared remarks. Joanna, we are now ready to open the line for questions.

Operator: Thank you. Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing *1. We will now begin the question and answer session and go to the first caller. Question comes from Greg Pardy RBC Capital Markets. Please go ahead.

Analyst (Greg Pardy): Yes, thanks. Good morning. Thanks for the rundown, guys. Maybe just a question for Corey to start is with the action maybe on reducing that debt here on the balance sheet, are you moving the goalpost in terms of your optimal financial leverage, or is this just being thoughtful around, you know, windfall cash flows versus purchasing stock right now?

Corey Douglas Code: Yes, Gregory, thanks for the question. So we are trying not to set a new long term debt target. Obviously, we have been carrying that $4 billion target for some time now. So this is really more a choice of allocating capital and just letting cash build on the balance sheet. Over time, you know, obviously, we will look at opportunities to take out further debt, but we do not have that much cash at this point that we gave at April month end number So it is about $400 million of cash on hand right now. Okay.

Analyst (Greg Pardy): Thanks for that. And, Brendan, for the last you know, few years, you just emphasized, look, the market's not looking for additional barrels to come on the market. Beyond the oil price escalation, which you know, may hang around longer than we think, Your increased focus in the Montney changes things because at the end of the day, right, Canada short condensate So my question for you is as you look forward, is there now a more compelling case to grow condensate in Canada? Or has you know, is what you are looking at just more temporary from an oil price and strategic perspective?

Brendan Michael McCracken: Yeah. Gregory, I think it is undisputable that there is a more constructive condensate fundamentals supply and demand dynamic that is unfolded here. You know, a few things have happened at once. And I will come back to the broader macro piece, but if we just touch on the condensate part that you have raised here first, You know, we are seeing pretty strong growth coming out of the oil sands and with the prospects for more, you know, a lot of egress projects being contemplated in Western Canada, which we obviously think is fantastic for Canada, but also for our business.

And all of that is putting pressure on the supply and demand fundamentals for condensate and driving that premium higher that is already happened, you know, where we have moved from a market where condensate traded a few dollars back to now a market where it is looking more like parity to TI. And then I think as the dynamics unfold and more oil sands growth comes, we are just gonna see more and more constructive condensate fundamentals. So that is the specific condensate part. I will just touch briefly on the overall macro and how we are seeing that unfold.

You know, a lot of dynamics there is a number of signals that we are watching very closely today to try and assess how much duration in the more constructive oil macro are we gonna see here? Because you know, clearly, we have got some pretty constructive front month dynamics. So, you know, this is not gonna surprise anybody, but we are watching closely to understand you know, when is the straight gonna reopen in a real way. What might be the impact of those barrels that are currently behind pipe or in storage once that happens. Also watching for what degree of demand destruction is underway. You are with these higher oil prices.

And then watching closely for the North American supply response. And the dynamics between OPEC and obviously, The UAE today as a former OPEC member. How are those dynamics gonna unfold? And then of course, in the major consumer markets, you know, principally China, how are their demand picture gonna unfold over time? So just a lot of different things that factors that we are watching unfold. But certainly a more constructive macro than we expect to coming into the year, and what we are looking for now is duration in that signal. Understood. Thanks to both.

Corey Douglas Code: Thanks, Gregory.

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

Analyst (Doug Leggate): Good morning, everyone. Thanks for having me on. Guys, I wonder if I could go to Gregory first. Just a simple question, Gregory, on the productivity comments you made. All very impressive. We all see the data. What we are trying to figure out is this recovery improvement or is it bringing forward production to the extent you have got enough data to be able to make that call at this point? And then my follow-up, if you do not mind, Brendan, is for you. And, obviously, thrilled to see the you know, the shift towards putting cash in the balance sheet. I think you know our view on that.

But I am curious to know when you talk about share buybacks justified on value, you said you are still seeing a substantial gap up mid cycle. What do you see as your mid cycle free cash flow that stands behind that statement?

Gregory Dean Givens: Okay. I guess starting, Douglas, thanks for your question on productivity. Mean, generally, we are just continuing to be incredibly pleased with the strong well performance we are getting from both the Permian and the Montney. I assume you are referring to the surfactant uplift that we are seeing in the Permian. there is a number of factors there that cause us to believe that is not but actually higher recovery. The first up proof point I would direct you to is the fact that we have been observing this phenomenon over the last 5 or 6 years. So we are seeing that, that uplift persist over a longer period of time.

Not just, it is not just a short term uplift. But also as a part of our surfactant, you know, diagnostic program we have been doing a lot of work with geochemistry where we actually fingerprint the oil And what we have seen in the wells that we pump surfactant in is we actually see a different oil come back. it is got a different composition. And so That tells us that the wells being treated with are not only performing better, but the oil comes back slightly different. And, that would point us to, yes, this is this is different oil. This is additional oil and not just acceleration.

But all of that together tells us that we are we are doing something different, and it is been sustained over a number of years now. So we feel pretty confident in Sounds good.

Brendan Michael McCracken: And then, Douglas, I can jump Douglas, this is Brendan. I can jump in on your question around mid cycle pricing and the cash flows. So when we look at the intrinsic value of the company on a per share basis, We would we would like to run that at our albeit what seems like today a conservative mid cycle price of $55 WTI, and we have kinda had that as our mid cycle price for quite a number of years. And so we just think that is a good discipline to look at the business through. Even though today, the supply and demand fundamentals would solve for a price probably more in the mid sixties.

But so if we look at that $55 w that implies about a $4 billion cash flow number for the business. And that is how we like to look at what is the intrinsic value how are we trading in the market relative to that intrinsic benchmark? that is really helpful. Thanks so much, guys. Yeah. Thanks, Doug.

Operator: Thank you. The next question comes from Arun Jayaram with JPMorgan. Please go ahead.

Analyst (Arun Jayaram): Hey, Brendan. How are you? Hey, Arun. Yeah. Greg. Good morning. Yeah.

Brendan Michael McCracken: Good morning to you and the team. Brendan, you and the team have spent a lot of times making moves on the portfolio with some good trades to kinda really clean up and, you know, improve the portfolio with the core focus on the Montney and Permian. Was wondering how we should think about portfolio management moves from here just given where the balance sheet's going to be and the fact that you are kinda long inventory at this point? Yeah. Appreciate it, Arun. Great question. You know, really, we think about the business now into a period of stability where we can sustain that inventory, depth that we have created.

So if you think about some of the larger M&A moves that we have made over the last few years, that is not our focus today. So we are very excited that we have reached this kinda milestone with the portfolio, and today, our focus is gonna be on driving incremental profitability. So we think that stability has got real value for our investors, and know, pleased to have put that behind us having to build this premium inventory position. So really puts us in a place now. We are operating from a position of strength We have the duration, and we can just focus on sustaining it.

And I guess I would also say we have shown with our organic ground game we have been able to replace that inventory on a really cost effective basis as we go. So sitting here, you know, just with the first quarter behind us, we have already replaced our 20 full year 2026 inventory consumption with the density conversion of about 130 locations in the Montney that we announced last quarter and then the Barnett position in the Permian effectively replaces the year of Permian consumption at least. And so we are we are excited to know, already be playing with a full deck for 2026. Thanks, Brendan.

Analyst (Arun Jayaram): And maybe a follow-up and maybe a house keeping question for Corey. On Slide 16, you highlight your guidance items in the deck. Including your updated views on kind of current taxes in a higher commodity price environment, Corey, you still are very minimal, US cash taxpayer in 2026. If we assume kinda strip pricing today, any thoughts on how cash taxes could trend, in The US in calendar 2027?

Corey Douglas Code: Yeah, Arun. Thanks. We all love getting tax questions on the conference call. So appreciate that. For The US, like, if you took if you took this year and replicated it again next we would expect a similar level of cash tax, so pretty minimal. And then into 2028, we come become more of a full cash taxpayer on The US side. Got it. Thanks a lot, Corey.

Brendan Michael McCracken: Yep. Thanks, Arun.

Operator: Thank you. Next question comes from Lloyd Borne with Jefferies. Please go ahead.

Analyst (Francis Lloyd Byrne): Hey. Good morning, guys. Thanks for having me on. Can you just start maybe, Brendan, with this concept of stacked innovation? And then why OVV feels differentiated in that and then kinda what that means for capital efficiency going forward. I know you talked about or Gregory talked about surfactants and AI and stuff. So how do we think about continued capital efficiency?

Brendan Michael McCracken: Yeah. Yeah. No for sure. And you know, we put stacked innovation as 1 of those critical strategic steps that you an e and p company needs to be able to hit home in order to deliver this differentiated value creation and so we think it is tremendously important. We think that is been true for a long time, but it is becoming more and more true particularly in North American shale because of the mass maturation of the of the resource. And so the companies that can demonstrate that capability are gonna demonstrate outsized returns and that should imply a lower cost of capital and a higher valuation.

So that is the buildup for why we think it is important. Know, really, what it is it is a long game. This is a industry where there is no intellectual property. There is no trade secrets. But there is the ability to create a lot of differentiation in whether you wanna look at returns or capital efficiency because of the method. And the method takes years and years to build up the learning and the capability. It takes a lot of work on the data side to build up the data to give you true causal results so that you understand by changing what input variable is controlling the output variable.

And so what we have been able to do is build a culture and an expertise here that has created that institutional learning over a period of really years that allows us to run at the forefront of capital efficiency and know, we take an I will call it an ambitious yet humble approach here. So we are, on 1 hand, very ambitious to try and lead this industry because there is a lot of great companies doing a lot of great things. But we are also very humble because we choose to learn from what is happening around us.

So we have focused very hard to build a unique private dataset that lets us to observe not only the innovations that our team is making, but also the innovations that every other operator around us is taking. And import those learnings into our system. You have you have heard me say the tagline here is the only infinite rate of return is learning from somebody else's capital. And so we have been really aggressive about doing that.

And when you look at every indicator of how that is turning out for us, whether it is the well performance results, whether it is our cost results, you look at the innovation pipeline of ideas that we have got running in the company today. You look at our data trade numbers, the knowledge shares that we do, the predictive models that we built, they all point to Ovintiv running at the forefront of the industry on an efficiency basis.

So we make the highest oil productivity wells in the Midland Basin, That is not an easy thing to do. there is a lot of great companies in the basin doing a lot of great work, and we are proud to have achieved that. We make the highest oil productivity wells in the Montney. And we do that while being the lowest cost operator in the Montney and amongst the 2 lowest cost operators in the in the Midland. So I think that is a long way of saying this is a whole series of activities and capabilities that we have built up over years and years that are now showing up in the results.

Analyst (Francis Lloyd Byrne): And I guess thank you for that. And is there 1 technology or change that you are still most excited about from here?

Brendan Michael McCracken: Well, in the rearview mirror, the technology that yielded a lot and has gotten a lot of market attention has been the surfactants. You know, if you look at our well performance data over the last several years, in the Permian, we are up 20-odd percent. On a per foot basis for oil productivity. And about half of that is coming from surfactant. So that is the rearview mirror. I mentioned this innovation pipeline that our team continues to try and fill up. And remember, it is not just the ideas we generate, but it is the ideas that are being tested and tried all around us that we are learning from that fill that innovation pipeline.

You know, we have got a number of other things that we are excited about deploying and testing over time. But I know, Gregory, if you wanna add anything to that.

Gregory Dean Givens: Yeah. I think it is a combination of improving well results but also improving costs. And some of the things that are exciting on the cost side is we continue to pump down more than 1 well at a time and continue to pump more hours of the day. We continue to pump more sand than our peers, but we do it for less cost. Because it is local wet sand, in many cases. So it is just a as Brendan was saying, it is a combination of all of these things.

If you start at where we are today and try to imagine how to replicate our performance, it would be very challenging if you had not walked the path that we have walked over the last 5 to 10 years. So lots of things have added up. there is still things in the hopper. We are not done yet.

Brendan Michael McCracken: And I think 1 of the things you have seen us pointing to and showing off And that, of course, is the big technology frontier here to use AI pair it with that private dataset that we have built, develop those in house algorithms to deploy, whether it is in our production operation centers that are driving uptime and artificial lift optimization. Or whether it is in our frac designs and tuning the 70 odd input design factors that go into each rack we pump on a real time basis. So yeah, the innovation pipeline is as full as it is ever been and excited about continuing to bring those into the field. Greg. Thank you. Excellent. Thanks.

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

Analyst (Neil Mehta): Brendan and team, I guess this is the last time we did a call, the earnings call, was only a couple weeks ago, we had we have had a large deal in the Montney at a significant premium. And just, you know, without commenting on the specifics of that specific you know, that transaction, just curious what you think that means for the way that you are thinking about the value of your Canada business?

Brendan Michael McCracken: Yeah, Neal. Appreciate the question. Yeah. You are right. Look, I think it continues to highlight the recognition that we have been pointing to with our actions and how we have been describing the Montney you know, that the capital is starting to be allocated globally towards the Montney. Not a surprise there. You know, we were not involved in that transaction in any way. We had already skated to where the puck was going there with the 2 larger transactions we have done in the Montney oil window to build the premier position in the oil window of the Montney.

So you know, we have we welcome the flow of capital and the recognition, and, obviously, there is a I think it is another way to point out the valuation gap that we see between the intrinsic value in our company and where our equity trades at, and so it is another way to try and look at the read through of what was paid for that other company combine that with how Permian trades, and you get a lot higher number than what is on the screen today for OVB. Yeah.

Analyst (Neil Mehta): No. that is definitely helpful. It? Just a follow-up is on NuVista integration. Slide 11 is helpful for us Wall Street folks. Maybe you can just explain that slide 11, the optimization of the pad and how changes in design are translating into results.

Brendan Michael McCracken: Yeah. I will turn it over to Gregory. it is a pretty compelling story just to set him up. That pad, we took over 2 days after it was spud. So you know, kinda really real time at closing, and it pretty incredible achievement by the team to do what they did there. But over to Gregory for the details.

Gregory Dean Givens: Yeah. I really appreciate the question and the opportunity to kinda dive in a little more. You know, kinda starting with just the map up in the top right, what, what we were able to take advantage of by combining these 2 acreage positions, we could take what we are gonna be, you know, fairly modest length laterals and extend them down into our acreage position. As we all know, longer laterals yield better cost per foot. So and this is just 1 of many opportunities. If you look along that lease line, you can see lots of opportunity to extend laterals from the NuVista lands over in the our position or vice versa.

So we were able to lengthen the laterals. We were able to tie in the wells to our drive center, that some of you may have toured when we were in Calgary last year. And that is our basically, our real time drilling optimization center. And so we were able to take all the results in from the rig, optimize those in real time, and drill those wells a couple of days faster than the NuVista was planning on drilling them at similar lengths. So were able to drill faster, and then we were able to, you know, incorporate some of the techniques we have been using for a long time. With local or domestic sand and simul frac.

We are able to pump those wells faster than you would normally have done. And all of those add into savings. And then finally, we were able to implement our facilities design We use a much simpler facilities design than NuVista was using, so we are saving about half off of the facilities cost. So just a great opportunity for the team to demonstrate what we promised when we announced the acquisition was that we would get to our well costs very quickly. So we budgeted that way. And on this very first pad, we are delivering at or below the well cost that we were, we were planning on.

So just a great execution by the team, really strong integration effort to hit the ground running just days after the acquisition closed. that is great, Gregory. Thanks for thanks for watching us do it.

Brendan Michael McCracken: Thanks, Neal.

Operator: Thank you. The next question comes from Gabe Daoud with Truist. Please go ahead.

Analyst (Gabe Daoud): Thanks, operator. Good morning, everyone. I was hoping we can maybe go back to the Permian Brendan and Gregory, guess, specifically. How much of the program this year is, pumping the surfactants that you highlighted? And then just also curious, just given the outperformance that you have seen with your curve this year, would it be premature to think that your 2 zero 5 to 12 oil and condensate guide could be maybe tightened or biased higher. I know that there is some headwinds with the royalty sliding scale on the Montney, but just curious how you think through that.

Brendan Michael McCracken: Yeah. I will maybe I will start with the second question and then Gregory can pick up the surfactant 1. You know, I gave, I think, the great news is the early wells of the 2026 program are really strong in both the Montney and the Permian, and we are not changing how we are planning the business at this point. So the type curve for 2026 still holds. But always really nice to play with the lead. And so the team's done a great job of that. Through the first quarter, and we will watch how that goes through the year.

But we know the direction of travel that is happening industry wide, and so what we wanted to point to with the results is, look, investors should feel really confident in this message that we have had for quite a while now, which is we are gonna be able to outperform and create differentiated results because of the work that we have built into the system here. So great to see the positive signal, but we have not changed the long term type curve plan for the Permian that over to Gregory on the surfactant.

Gregory Dean Givens: Yeah. As far as our application of surfactants, we have really advanced our approach here over the last several years. If you were to go back in time, you know, initially, we were only pumping on a small number of wells. Our costs were something we were working to bring down, but we have worked to really you know, hone in on the right formulas for the right zones. I have gotten our cost down to a $100 thousand a well. And so just for kinda walk you through the last few years, in 2024, it would have been about half of our wells got, surfactant treatment. In 2025 or last year, it was about 75% of our wells.

And this year, it will be almost all of our wells will be treated with surfactant. You know, we are still you know, toying around with a few zones. The Barnett, for example, not exactly what we would pump in that yet when we do that later this year. But almost all of our wells will get surfactant treatment, and we are doing it at a very low cost. And as we talked before, seeing, you know, very solid uplift there. So, but it will be essentially all the program.

Analyst (Gabe Daoud): Got it. Got it. Okay. that is helpful. Thanks, Gregory. And thanks, Brendan, on the other question. And I guess just as my follow-up, your D and C per foot pretty attractive in both plays, and I know historically you would you would also highlight what the pacesetter is in both plays. So I guess just curious on that number might be today. Again, I know there is maybe some inflationary pressures that could be down the road, but nothing today. So curious what those pacesetter wells maybe look like on a D and C per foot basis and then maybe reasonable expectation around when the pacesetter becomes the play average. Thanks, guys.

Brendan Michael McCracken: Yeah. I will turn it over to Gregory, but that is a good example of this innovation pipeline in action. So you know, we love the pacesetters on the cost side because they tell us what is possible. And then we go and chase that to make what is possible the average outcome. And so yeah, over to Gregory on what we are seeing there in terms of you know, days per foot feet per day on the frac and drilling side, giving us some confidence there is still move room to move on the well cost side.

Gregory Dean Givens: Yeah. it is great question. This is something we are always watching. We continue on both sides of the border to both drill and complete our wells you know, faster than we ever have before. We are continuing to, you know, drill You know? And it is it is gotten to where it is harder to take off days and weeks like we used to be able to take off, but we are still seeing improvement on the drilling side. We have had, you know, the last few quarters have been some of our fastest quarters. But we are working, you know, to offset. there is a little bit of inflation in the system right now with diesel.

Cost being mainly passed through diesel cost. So I would say that we are continuing to, you know, trim half days and days off the drilling side. We are continuing to trim days off of the completion side. And today, that is got us, you know, comfortably saying we are still below $600 a foot in the Permian and $500 a foot in the Montney. But if we continue to have those faster cycle times, as we see, you know, the inflation, we think, ease a little over time, then that will start translating in lower well cost But right now, we feel very comfortable with the guide that we have out there today. Understood. Thanks, Gregory. Thanks, everyone.

Brendan Michael McCracken: Thanks, Gabe.

Operator: Thank you. The next question comes from Philip Jungworth with BMO Capital Markets. Please go ahead.

Analyst (Phillip Jungwirth): Thanks. Good morning. I wanted to ask about how you see the production growth optionality in the Permian now. it is an asset where you have low to mid teens inventory life. it is a good runway, although not quite at the Montney levels. With the ability to grow the Montney 5% , what is the scenario where you would also look to grow the Permian? And could a higher plateau than 120 thousand a day of prudent condensate makes sense, noting that I think you are at 125 thousand in the quarter.

Brendan Michael McCracken: Yes, Phillip. Thanks for the question. I think we would see the option to grow in both places pretty much the same. I think if we went to growth, which we are you know, we thought long and hard about here, we would likely do it in both places. You know, the return proposition is the same in both, and we have the from, as you said, from an inventory position in both So you know, we do think that is a very real option. We are saying today we are gonna be patient.

And watch the macro unfold a little bit longer here, but we do have the option in both places, and we worked hard to build that capability over the last several years. So you know, in the meantime, we are just gonna continue to lean in on performance to direct generate upside barrels in this price environment and, you know, watch how the macro unfolds.

Analyst (Phillip Jungwirth): K. Greg. And then you noted earlier the stock still trades below intrinsic value. I think most of us would agree with that. S and P is considering adding companies not domiciled in Canada to the S and P TSX indices at reduced 50% weighting. Wondering if you have looked at this or have any thoughts as it relates to Ovintiv and expanding the investor base up north just because being in the bench can help. there is obviously fundamental element to the story here with having a leading Montney position and Art going away.

Brendan Michael McCracken: Yeah. So, Bubba, I think the combination of those fundamental improvements to the business, which we have spent enough time probably harping on today already, so I will not reiterate again. But the combination of those with that potential index inclusion would be quite constructive. You know, we have we have seen the S and P reach out to investors for comment on that concept, and, obviously, we are enthusiastic supporters of it. So we will we will keep our eye on that 1. But I think the more important part is the fundamental appetite to own the shares is strong today in both Wall Street and Bay Street, and we are seeing that in investor sentiment and interest. Greg.

Thanks, guys. Yeah. Thank you, Phillip.

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

Analyst (Kevin MacCurdy): Apologies for staying on the subject of growth and shareholder returns. But my question is maybe about the calculation here. In the past, you have seen value in buying back your stock versus growing production. My question is, is there any update to how you calculate you know, when you are siding between those 2 uses of cash are you using the strip? Are you using mid cycle prices? Kinda how do you how do you calculate that?

Brendan Michael McCracken: Yeah. Kevin, good question. We have been looking at it across a range of prices. that is that is kind of been the approach over the last several years to look at that. And, really, the fundamental intention we wanted to create is cash flow per share growth and the most efficient cash flow per share growth. And what I would say, and we had said for quite a number of years, is that cash calculation kept telling us buybacks were more efficient. Today, that is moved much more into a balanced position. So today and, again, it does depend, which is your question on which price, which oil price to use.

But even at a more modest oil price, that relationship has moved more in the balance. So it opens that door a little more than it was the last several years. So we like that. It creates a real option for cash flow per share growth value creation for us. Appreciate that.

Analyst (Kevin MacCurdy): And maybe it is my follow-up, I will shift gears to OpEx. Upstream T and P was much lower than the guide in Q1. You chose to keep your Q2 to Q4 guide kind of intact. Can you talk about the moving pieces there? Of that line item in light of all the transactions that happened in the first half of the year?

Gregory Dean Givens: Yeah for sure. I will take that 1, Kevin. So I guess first thing I would say is Q1 really is just a bit noisy on TMP. So a couple of the puts and takes there, it included our Anadarko volumes, which has a lower T and P rate. It includes some, but not all of NuVista. You know, we did not have NuVista for the whole quarter, which is gonna be at the higher Canadian T and P rate, which is similar to our other Canadian assets. But we also had some onetime adjustments in the quarter that were in our favor.

So that really just Ended up pushing down T and P to lower than our normal run rate in Q1. Is the way you should read that. But go forward, our T and P is right in line with what we have expected. So if you kinda think about it holistically, Canadian assets typically have more of their cost in the T and P side of the structure. Whereas US assets, it is more on the LOE side. So going forward, you will see LOE come down OpEx come down. T and P will be up slightly, but all of this is very much in line with what we have expected all Appreciate it, Gregory.

Brendan Michael McCracken: Thanks, Kevin.

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

Analyst (Neal Dingmann): Hi, good morning guys. Thanks for the time. Probably for Gregory. Gregory, my question is on the Permian plan this year. Since specifically, I believe you all target around 125 to 135 wells Will most of this continue to target Wolfcamp Spraberry? Are you targeting some deeper zones as well like the Barnett Yeah.

Gregory Dean Givens: it is thanks for the question, Neal. Yeah. Pretty straightforward program. We have got 1 Barnett well in the program. So the rest of the, the zones we will be targeting will be the normal stack going from Spraberry, Dean, you know, Jomel all the way down to the Wolfcamp. But no real exposures Barnett other than that 1 test we are doing this year. And that is really, as we have said before, we find our Barnett acreage interesting, but we do not have the same maybe drivers as some peers and that our Barnett acreage is held by production. So, we are gonna kinda take a slower approach.

We really like the productivity of the zone, but it is the cost question that we are still trying to answer. I think over time, we will see as others and ourselves learn more about the zone. We will get better. We will get faster. We will get cost down. But this is a great opportunity. it is like Brendan was alluding to earlier. Learning from peers, this is a great place where we can learn a lot without spending dollars. So we will be watching our peers and learning from them on the best ways to drill these Barnett wells cheaper.

Analyst (Neal Dingmann): Yeah. That makes sense. And then just secondly on marketing, for the guys specifically, in the firm, are you seeing near term power opportunities or anything you are considering there?

Gregory Dean Givens: You know, we constantly look to try to, you know, lower OpEx there. But as far as, you know, engaging in another line of business, around generation or power, if that is what you are alluding to, that feels, beyond scope for us today. But we are always looking at, you know, innovative ways to lower our both our OpEx and, you know, generate power for our electric frac fleet cheaply as possible. So we are looking at interesting things there, but, but probably a narrower scope than what you might be referring to. that is what I was looking for. Thanks, Gregory.

Operator: Thank you. And the last question will come from Christopher Baker with Evercore. Please go ahead.

Analyst (Christopher Baker): Hey, guys. Thought I took down my hand. All my questions have been answered, but I appreciate the time today.

Brendan Michael McCracken: Hey. Thanks, Christopher. No problem.

Operator: At this time, we have completed the question and answer session, and we will turn the call back over to Mr. Verhaest. Thanks, Joanna. Thank you, everyone, for joining us today. Call is now complete. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.

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