Ovintiv Inc. (OVV) Q3 2026 Earnings Call Transcript

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Oventiv's 2026 Third Quarter Results Conference Call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question and answer session. Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing star 1. For members of the media attending in a listen-only mode today, you may quote statements made by any of the Oventive representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Oventive. I would now like to turn the conference call over to Jason Verhaste from Investor Relations. Please go ahead, Mr. Verhaste.

Thanks, Marissa, and welcome to our third quarter 2026 conference call. This call is being webcast, and the slides are available on our website at eventiv.com. Please take note of the advisory regarding forward-looking statements at the beginning of our slides and in our disclosure documents filed on EDGAR and Cedar Plus. Following the prepared remarks, we will be available to take your questions. I'll now turn the call over to our president and CEO, Brennan McCracken.

Thanks, Jason. Good morning, everybody, and thank you for joining us. We are excited to talk to you today about another great quarter in our acquisition of Motney oil producer, Logan Energy. A very clear competitive advantage is emerging for companies like ours that have best-in-class assets, a clean balance sheet, access to premium price markets, and a demonstrated execution advantage that translates to superior and durable returns. That combination of attributes is truly differentiated, and it's what we're delivering today. Our third quarter results continued our track record of industry-leading execution driven by our stacked innovation. Our culture, expertise, and unique private data sets have created a distinct enterprise advantage that is showing up in our bottom line. Our cash flow per share and free cash flow both beat consensus estimates once again, and our balance sheet remains strong, with leverage at 0.7 times. We returned approximately 69% of free cash flow in the quarter to our shareholders through share buybacks and our base dividend. The Logan acquisition does not change our 2026 target payout ratio of at least 60%. We continue to see a substantial gap between the market value and the intrinsic value of our business. Year-to-date, we have returned 53% of free cash flow, or just over a billion dollars, to our shareholders. This implies another quarter of strong buyback activity in 4Q to reach our full-year plan. We announced last week that we have entered into an agreement to acquire Logan Energy, which adds to our top-tier position in the Montney oil window. Transaction is priced right. It adds significant inventory in the heart of one of our two core plays, and we expect it to create exceptional value for our shareholders. It is immediately accretive on all financial metrics, comes with a deep inventory of drilling locations, and substantial oil-rich production. It also brings valuable infrastructure ownership and spare midstream capacity, which adds to our future growth optionality and increases our margins. We identified the Logan-Montney assets through our in-depth technical and commercial analysis. That same analysis highlighted the NuVista and Paramount assets we've acquired over the last two years. These positions screened as being attractive and complementary for our existing Montney acreage. And we are uniquely positioned to create superior value from them. The Logan assets sit in the Montney oil window are largely undeveloped, adding approximately 420 net 10,000-foot equivalent well locations across 200,000 net core acres. This includes 220 premium locations and 200 upside locations. The assets are currently producing 20,000 BOEs per day, including 7,000 barrels a day of light oil. Importantly, we are acquiring this high-quality inventory at $1.5 million per premium undeveloped well location. This drops to $0.8 million per location if we include the upside inventory. This highlights our ability to identify and opportunistically add inventory with superior full-cycle return propositions relative to other recent market transactions in both the lower 48 and the Motney. We expect to deploy a rig to the Logan Acreage immediately upon closing, bringing our total Motney rig count to seven. We will evaluate the possibility of adding a second rig as we continue to work through our 2027 capital plans. The acquisition also comes with ownership of two new oil batteries with a combined capacity of 24,000 barrels per day and ownership in two natural gas processing plants. This infrastructure enhances our future growth optionality and will also benefit our Overall, Monty margins with a lower fee structure. We expect to capture about $60 million in durable, annualized, free cash flow synergies. The majority of these are driven by lower capital costs. We expect to achieve cost savings of $2 million per well, consistent with our current Montenegro well costs. The savings will come from faster cycle times, drilling longer laterals, domestic wet sand, simul frac, and streamlined well site facilities design. Balance of the synergies, about $5 to $10 million, will come from lower production costs and lower overhead. We are highly confident in our ability to realize these cost savings, given our strong track record of asset integration with NuVista and Paramount, where our targets were achieved within months of owning the assets. We expect the Logan integration to be more of the same. We've been very successful this year in bolstering our drilling inventory. Our disciplined approach ensures we are acquiring new locations at an entry cost that will deliver superior full-cycle returns through the commodity price cycle. When we pair our unique ability to secure inventory with our stacked innovation execution, the combination is creating a clear competitive advantage for Oventus. Starting with the NuVista acquisition that closed earlier this year, we added 930 drilling locations at an average cost of $1.3 million per location. When we add in the 420 locations from the Logan transaction and the 240 Permian and Motney locations from the 2026 ground game, we've added just shy of 1,600 new drilling locations this year. We also converted several hundred upside locations to premium this year between the Barnett and the Permian and the density conversions in the Motney. All of these locations compete for capital today. This level of expansion at these full-cycle returns has been unmatched by our peers, as comparable industry transactions baked in much higher entry costs, and industry data continues to show that our peers' inventory lives are generally getting shorter. We can deliver superior full-cycle returns for many years to come in the Permian and the Motney because we have captured a long runway of high-quality inventory at the right cost. And we have a proven track record of optimizing asset development via our differentiated operational execution. Our stacked innovation approach is separating us from the competition on oil productivity and on costs. Our expansive private data set has been a key factor in our ability to achieve this. It's an aspect of our business where we have taken a very deliberate and unique approach. Every decision we make, from the details of our frack designs to our capital allocation choices, is rooted in careful technical and commercial analysis. The value of that analysis depends in large part on the input data we are able to feed into it. Building a unique and large data set has been a strategic priority for us. We've accomplished this by merging our own data that we get as we drill our wells with a decade's worth of deliberate data trading with our peers. As a result, we now have high-fidelity private data on almost half of the 30,000 horizontal wells that have been drilled in the Midland Basin. When we combine an advantaged data set with our expertise and our culture of relentlessly stacking innovations together, we get exceptional results. Our proprietary data set underpins our stacked innovation model, helping us accelerate successful innovations, avoid unsuccessful ones, and train AI models that optimize technical and operational execution. Applied across our portfolio, these insights are improving cycle times, production, reliability, costs, and resource predictability, driving higher profitability and returns. As a result, we are consistently one of the highest oil productivity, lowest cost operators in both the Permian and the Motney. We are creating more than just a competitive advantage. We are creating a durable moat around our return outcomes that is proving difficult to replicate. I now turn the caller to Corey, who will speak more to our third quarter results and our guidance updates.

Thanks, Brendan. The third quarter continued to build on our track record of translating excellence in our operations into strong financial results. We delivered cash flow of $4.51 per share and free cash flow of $680 million, both beating consensus estimates. Capital came in below the midpoint of our guide, and our total production volumes came in just above the midpoint. We continued to see strong performance from the Permian, which delivered oil and condensate volumes of 127,000 barrels per day, above our guidance of 125,000 barrels per day. Motney oil and condensate volumes came in at 77,000 barrels per day due to the impact of higher-than-expected Canadian royalty rates and some extended downtime at a third-party natural gas processing facility. This brought us in just below the low end of our guidance range for total company oil and condensate at 204,000 barrels per day. We remain very pleased with our Montney and well performance, which continues to track above our type curve expectations. Our balance sheet remains strong and is backed by deep liquidity profile with no maturities until 2030. We repurchased $109 million of long-term notes in the open market across a number of maturities during the quarter. We expect the payout from these debt repurchases to be less than six months. This demonstrates our ongoing commitment to managing our balance sheet in a value-enhancing way. Our net debt balance at quarter end was about $3.4 billion. The increase from the end of the second quarter reflects the cash outflow for our Permian and Montney ground game acquisitions, along with some normal course working capital adjustments. Our leverage ratio was 0.7 times, which we are very comfortable with. Assuming strict pricing, we expect our net debt at the end of the first quarter of 2027, following the close of the Logan acquisition, will remain below $4 billion. Although we have not re-established a net debt target, we will continue to manage our balance sheet and capital structure conservatively. Our outstanding performance through the first three quarters gives us confidence that we can deliver a strong finish to the year. Our fourth quarter total volumes are expected to average approximately 628,000 BOE per day, with oil and condensate volumes of approximately 205,000 barrels per day. Using current strip pricing, higher Canadian royalties will continue to put pressure on our reported condensate volumes. Obviously, the higher commodity prices also result in strong realizations and more cash flow. We're also assuming the Albright gas plant remains offline for the remainder of the year. As such, we've chosen to reallocate $50 million of capital from the Montany to the Permian to minimize the impact on our volumes. This is the strength of the two-basin model and the short-cycle nature of our business. We can easily redeploy capital to keep our corporate level of objectives intact. Our fourth quarter capital spend is expected to come in around $575 million, consistent with the last two quarters. Aside from a slight increase to our expected NGL volumes, Our full year guidance remains unchanged. Our oil and condensate guide of 210 to 212,000 barrels per day remains intact. If you recall last quarter, we raised our oil and condensate guidance by about 2,000 barrels per day. This was driven by operational efficiencies with no additional activity. When we combined that with our share buybacks since March 1st of approximately 5% of our total shares outstanding, this equates to an annualized per-share oil growth of about 6%. When we factor in our fourth-quarter plan buybacks, this jumps to an impressive 8% to 9% per share. Given the strong oil price backdrop, we think top-line growth in the low single digits, driven by industry-leading operational efficiency, provides compelling value for shareholders. We've also adjusted our cash tax guidance to include the impacts of higher expected oil prices for the remainder of the year, and an anticipated $25 million tax benefit in our Canadian business. This is the result of the Canadian federal government's recently announced productivity mega deduction. We expect our 2027 cash tax savings from the bill to total approximately $100 million. These deductions are expected to be durable for the next several years. I'll now turn the call over to Greg, who'll speak to our operational highlights.

Thanks, Corey. Capital efficiency and free cash generation remain our top priorities as we work to drive efficiency into every aspect of our operations. I'm very proud of the team for continuing to find new ways to improve cycle times and drive down costs. Even during a year of higher oil prices, we've maintained an intense focus on capital efficiency. Our 2026 capital program is unchanged as the team is continuing to offset inflationary pressures, such as higher diesel prices seen across the industry and the broader market today. The competitiveness of our portfolio and the agility of our operations offer multiple pathways to deliver the best corporate outcomes and drive superior returns. Let's dig into each of our two asset-level development programs. Our Permian Well results continue to demonstrate the value of stacked innovation. Our year-to-date performance has exceeded our type curve, which is unchanged from last year. The production benefit from some very strong wells that were brought online earlier in the year continue to dominate our year-to-date actuals. Our team continued to establish new pace setters in the quarter by drilling our fastest ever 15,000-foot lateral. Our pace setter pad averaged over 2,500 feet drilled per day. On the completions front, last quarter marked our third quarter in a row, where our pump time averaged more than 20 hours per day. This impressive performance is improving cycle time and lowering costs. With average third quarter oil and condensate volumes of 127,000 barrels per day, our Permian outperformance has helped us maintain our full-year oil and condensate guidance, despite some extended facility downtime in the Motney. As Corey mentioned, we have shifted $50 million of capital from the Montany to the Permian to accelerate completions activity through year-end. As a result, we expect our fourth-quarter Permian oil and condensate volumes to average 125,000 to 130,000 barrels per day. Using public data, you can see that our Midland Basin wells continue to outperform our peers. Our Permian Well productivity has been increasing every year since 2023, while many of our peers have experienced performance degradation. There are several factors at play here, including our cube development and reoccupation strategy, the use of custom surfactants in our completions, and our enhanced stage architecture design. Our base production is also outperforming year-to-date, and we expect to see a 3% improvement in base decline versus our original plan. The third quarter set a record for highest artificial lift uptime, largely due to the remote operating capability of our Permian Operations Control Center, where the team is using AI and automation to optimize artificial lift parameters. This is technology we imported from the Motney, and we are now seeing the benefits across the portfolio. Shifting over to the Motney, we continue to see strong year-to-date well performance, which is exceeding our 2026 type curve. However, oil and condensate volumes came in below our guide this quarter due to higher-than-expected Canadian royalties and an unplanned outage at a third-party-operated midstream plant. The Albright plant went down in July due to a leak in its sulfur recovery unit, and it remains offline. Our team was able to mitigate the impact of the outage on our third-quarter volumes to about 3,000 barrels per day. As Corey mentioned, our guidance assumes it will remain offline for the rest of the year. In the meantime, our team is actively working to identify opportunities to optimize our base production and adjust activities to minimize the impact of this outage. While higher condensate prices resulted in higher royalty rates and lower reported production, the revenue uplift far outweighed the impact of the lost volumes. Our realized price for Canadian condensate year-to-date is basically at parity with WTI. So although we don't like losing the reported volumes, the revenue uplift is a trade we will gladly make. When we combine the royalty impact of current strip pricing with the assumption of continued plant downtime, we expect our fourth quarter Montany condensate volumes to average 75,000 to 80,000 barrels per day. While the economics of our Montany program are dominated by high-value condensate, our gas realizations at 193% of ACO year-to-date continue to drive significant incremental revenue. This is thanks to our gas price diversification strategy, and more recently, due to the impact of historically high sulfur prices. Typically, we incur an expense to extract this product from our gas stream and transport it to the West Coast market. In the third quarter, however, continued high sulfur prices contributed about $75 million in cash flow, which is captured in our realized gas price. While it's hard to predict longer-term global sulfur supply and demand dynamics, we do expect prices to remain strong for the rest of the year. Our Motney team continues to push the boundaries in our development approach. We have successfully transferred learnings from the Permian, the most competitive basin in North America, that are driving differentiated performance outcomes versus our Motney peers. Year-to-date, our completion speed is averaged more than 4,900 feet per day, about 40% faster than the current pace of our peers. We're the only producer using Simulfrac, and we recently established a pace setter of more than 7,000 feet of completed lateral length per day. We also achieved an industry milestone with the first-ever 100% domestic wet sand pad in Canada. Compared to importing dry sand to the Motney, domestic wet sand is roughly 20% cheaper. We are also starting to trial surfactants in the Montney this year. It's still too early to predict the potential for oil production uplift, but we are seeing some encouraging initial indicators. While implementing these stacked innovations requires sophisticated logistics management and deep technical expertise, it's a lot easier when you've already done it at another basin. We have a level of insight and experience that our Montney peers simply do not have. It's a huge advantage for us and has helped us secure our position as the undisputed leader of the play. I'll now turn the call back to Brendan.

Thanks, Greg. I'd like to touch on the robust fundamental outlook that is developing for longer-term condensate demand in Western Canada. In fact, we've never seen a more favorable setup. Because it is used as a diluent to allow oil sands bitumen to flow through pipelines, condensate demand grows when oil sands volume grows. Production for growth from the oil sands, thanks to several new proposed pipelines, range from 1 million to 3 million barrels per day. Every million barrels a day of bitumen growth would require 300,000 barrels a day of additional condensate. With current domestic supply of about 500,000 to 600,000 barrels per day, Canada is already structurally short condensate by about 50%, and import pipes from the U.S. are largely full. This means that the vast majority of incremental condensate demand must be met by some combination of growth from Western Canada, import expansion, and or substitution from other light and medium oils. Condensate is already the only premium resource product produced in Canada. Even pipeline expansion at the low end of the proposed range would further tighten an already import-dependent market, so we have high confidence that Canadian condensate will continue to realize strong pricing for many years to come. 2026 has already been an exceptional year for Oventive. We are excited to run through the tape and into 2027. We have built one of the most valuable premium inventory positions in our industry. We have worked diligently to focus and high-grade our asset base while right-sizing our balance sheet. We are set to grow oil production per share by 8% to 9%, with no increase to activity or capital spending, and we are on track to deliver record annual free cash flow. Our track record of asset integration and operational excellence gives us confidence in our ability to deliver. Oventip combines best-in-class assets with unmatched execution excellence and disciplined capital allocation. We are one of the most opportunity-rich EMPs in North America, and we are very excited to be operating from this position of strength. This concludes our prepared remarks. Marissa, we're now ready to open the line for questions.

Wonderful. Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing star 1. We will now begin the question and answer session and start with our first caller. Your first question comes from Scott Gruber with Citigroup. Please go ahead.

Yes, good morning. Brendan, you mentioned the potential to add another rig to the Logan assets. You know, would this take your, if you choose to do so, would this take your money rig count to eight, or would you transition, you know, from your current program and keep it at seven, just in color of what you're potentially contemplating there?

Yeah, hey, Scott. Yeah, so an additional rig on the Logan acreage would move us from six legacy rigs into seven. So that's kind of the math there. And like we said, we'll evaluate our 2027 plan, whether we turn that one incremental rig into two. That's going to be a question probably for our next call, but that's something that we're looking at.

Well, if you did two, though, those would both be incremental? I guess that's the question. Or would it transition from your current program?

Yeah, that's right. Yeah, that would take us to eight, and that would probably create growth in the monty oil production.

Okay, great.

Way to think about that.

Yeah, yeah, yeah.

Okay. And then you mentioned, you know, looking at a kind of low single-digit type growth and, you know, what we just discussed on adding incremental rigs to Logan would help propel that in the Motney. Just maybe some color and how you're thinking about, you know, delivering some growth, Montany versus Permian is the Canadian backdrop here in the Logan acquisition, you know, leading you to kind of lean in on the Montany over the Permian, or would you, you know, look to grow both assets? In the past, you've talked about kind of a balanced.

Yeah, I think sitting here today, Scott, we're still in the balanced mindset. We have the flexibility to bias one way or the other, depending on what signals the macro and the returns are telling us. At least in the band of volatility that we're seeing in the space today, it's probably still leaving us in a balanced growth mindset. Today, you know, this year, the approach to growth we've been taking is create low single digit top line production growth through efficiencies. So we have an added activity to create that this year, and then top that up on a per share basis with the buybacks. That's on track to take us to about 8% to 9% per share growth this year, which we think compares very strongly. And then, you know, we'll make those capital allocation choices as we head into 2027. But that's been the mindset this year with the environment we've had in front of us.

I appreciate that. Brendan, I'll turn it back.

Yeah, thanks, Scott.

Your next question comes from Arun Jaram with J.P. Morgan. Please go ahead.

Yeah, good morning, and thanks for taking my question. Brendan, I was wondering if you could... Give us an update on your read on the regulatory climate in Canada. Obviously, there's been some tailwinds with the mega deduction and the MOU undergoing with key producers. Can you give us the thoughts on how this could influence your capital allocation in Canada, particularly given the tight supply-demand balance for condensate, which could grow tighter? Yeah. If we get more oil sand supplies.

Yeah, thanks, Arun. You know, look, I think this validates the strategy we've pursued in Canada, which is to focus on the premium product condensate and also the product and acreage that is well risk-managed relative to the regulatory environment. That said, you know, that strategy had upside in it, and that's what we're seeing unfold over the last number of quarters in Canada. We're the tailwinds around gaining market access for all resource production in Canada, you know, have created a more favorable pricing environment and created a lot of, you know, value for our shareholders. So we like the direction. We applaud the direction. I think permitting reform is on the table in both countries that we operate in and an important aspect to ensure that the... Both economies are gaining the upside to the products that they produce and export to the world. So we're big supporters of that direction, and it has turned into upside for our shareholders.

Great. In my follow-up, I was wondering if you could talk about some of the changes you've been able to make in terms of capital allocation. You reallocated $50 million from the Montany to the Permian to mitigate the impact from the third-party Albright plant in a kind of downtime. Maybe elaborate on that. And Greg, maybe you could just give us an update. On your understanding of when the Albright plant could return to service and perhaps the impact to your production from that outage.

Yeah, I'll set Greg up here. I think he's got the details. I think on Albright, there's kind of two ways this is going to go. The plant returns to production in short order, or we mitigate the impact down to negligible. So those are the two pathways that we're pursuing today, and I'm pleased that the team's already got a good head start on the mitigations, but I'll head it over to Greg here on the details.

Yeah, so thanks, Brendan, and thanks for the question. Starting off with Albright, first of all, I'm just really proud of how the team reacted to this unplanned outage. We were able to mitigate the impact down to 3,000 barrels a day in the quarter, and they're continuing to find ways to adjust our activities and reroute the gas to other outlets. We're told the plant should return to service later this year. They've identified what the problem is. They're working to fix it. So we've modeled the end of the year in our guidance. We're going to wait and see how that works. But the team continues to look for ways to minimize that impact on our operations. And one of the ways we're mitigating that is shifting capital both within the Motney and then shifting capital from the Motney to the Permian. And if we think about that shift, you know, that's really just us leaning into the flexibility of our portfolio. We were able to move the capital to the Permian where, you know, the team had been doing a great job operating year to date. Our drilling performance was a little ahead of schedule. So it just allowed us to accelerate some completion activity there in the Permian and then push out some completion activity in the Motney just to give us a little more time to see how this Albright situation sorts out. So it just really highlights the benefit of having two world-class basins you're operating in. You can shift capital between the assets when you need to adjust to external situations. So just proud of how the team has performed, and we've got a lot of flexibility that allows us to deal with situations like this.

Great. Thank you. Thanks, Rene.

Your next question comes from Josh Silverstein with UBS.

Please go ahead.

Hey, thanks. Good morning, guys. Maybe back on the potential for growth on the Logan assets, you know, they had outlined the path towards doubling volumes in a few years. I know you guys are still, you know, early in figuring out the right pace of growth for you, but can you talk about the available infrastructure to support this level of growth, maybe potential, you know, capital additions that you would have to make before it kind of gets to that level that's closer towards, say, $35,000, $40,000 a few weeks ago?

Yeah, thanks, Josh. Yeah, as part of the value we saw in the Logan assets was the infrastructure and the spare capacity in that infrastructure, but I'll flip it to Greg to fill in the details.

Yeah, I guess the first thing I'll start with is, you know, we're not ready to set firm guidance for next year, but maybe I'll give you a framework on how we're thinking about it. The Logan team had done a really good job setting up and building infrastructure to grow this asset, as you stated. We're at 7,000 barrels a day right now. There are two oil batteries, one that is online and one that is about to come online that would allow us to more than double that oil production. We have gas takeaway that will allow that as well. So think about it as taking a 7,000-barrel-a-day asset. You could take it to the mid-upper teens over time, but again, we're not saying that we're going to do that yet. We are going to put one rig on the asset to start, which is kind of think of that as keeping it at seven, and then we could add a second rig sometime during the year to grow that next year. But really excited about the asset and the opportunity that it provides for us. You think about capital, big round numbers. We usually use around $200 million per rig per year for both the drilling and completion capital. So you think about that for each of the two rigs since they're additive to our base program.

And I just flagged to that, Josh, too, the working interest is 100% on this Logan acreage, so that's a factor in that capital sensitivity Greg just gave you.

Yes, that's a good point. It's a little higher than on our legacy money.

Gotcha. And then maybe if you can do a little comparison just on the Logan inventory versus the quality of it versus... The existing inventory for competing for capital purposes, and then what drives the upside for the additional couple hundred locations? I know you've done some wine rack development. Is that sort of what you'll be doing on this asset to go and test that upside potential?

Yeah, so a couple of things, you know, we're really excited about there's several areas in the Logan asset base. So if you think about the position down at Simonette, that's, you know, kind of think about that as comparative to our car and Wapiti positions, which compete very favorably, you know, the oil per foot there is in line with what we see down in the Permian. So really, really competitive returns on some of the zones there in Simonette. When you move up to Puscoopy, that's more like our Pipestone asset. Again, very competitive returns there, just slightly lower oil per foot. When we think about zones, you know, we bought this asset specifically for the Motney, so I'll just speak to the Motney. We've got three different zones that come into play in varying parts of the asset base between Puscoopy and Simonette. And so we'll be looking at ways, you know, we've kind of looked at a very base, you know, four-well per section kind of look in the valuation. There appears to be room to go more than that, but, you know, that'll take time for us to test. They're only about 20% developed on this asset in the Montney, so a lot of running room, a lot of chance for us to look at upside. So those upside zones would be either, as you said, you know, a wine-racking, you know, density-type look, or some places in the asset that just haven't been tested yet, So we don't really have the information we need to call that base, but with some drilling, we could easily convert more of that inventory over to our base inventory. So a lot of opportunity there.

Thanks, guys. Thanks, Josh.

Your next question comes from Doug Leggett with Wolf Research.

Please go ahead.

Good morning, everybody. Hey, Brendan. My question is on the Logan synergies. So when you look at the capital trend, if I go back to 2025 through the beginning of this year's guidance, On spending and sustainable oil production, it looks like your capital efficiency is moving, obviously, in the right direction, but I wonder if you could put some numbers around it when you strip the Logan synergies out of it. Sustainable oil and sustaining capital, it goes along with that. And I've got a quick follow-up, please.

Sure, Doug. Yeah, good morning. Thanks for the question. I think, generally speaking, this year's capital efficiency trend has been very much in line with the year prior. We're seeing something in the order of 5% capital efficiency gains. Now, a little bit of that has been eaten up by some inflation pressure on diesel, although the team's done a really nice job of mitigating that with buy fuel and electric spreads and rigs. And then a little bit in the OCTG, but again, our team's done a really nice job with the contracting strategies there to mitigate and offset some of that. So that's kind of the interplay that you're seeing netting out in that capital efficiency that's allowing us to grow top-line production, low single digits this year. So I would expect that's going to continue as we head into 2027. We're certainly continuing to see upsides. Greg has flagged a few of the pacesetter results in both the Montany and the Permian on costs, and so we're continuing to look to see that efficiency gain be able to offset inflation and hopefully even do a little bit better than that, but obviously a little bit of water to come under the bridge on how the... The service pricing evolves into 2027 before we get definitive on that.

I appreciate that. I hate to come back to a question that might have already been asked, or at least I'll get slightly differently, but it's maybe for Greg. When you look at the productivity of your wells, obviously peer leading, and compare them to Logan, what we're kind of thinking is Logan's got some existing... Um, excess infrastructure capacity. And if you close the gap between the productivity, you know, between their productivity and your productivity, we're kind of wondering if you can end up getting that growth anyway on the same capital numbers. Are we thinking about it the right way or any color you could offer, Greg? Thanks.

Um, yes. Well, first off, you know, the first thing we're going to do when we get control of the Logan asset is going to be working to get the cost structure more in line with our cost structure. We feel like they've already have very attractive production rates from the Montney zone. So we'll be working and we're talking about over a period of months here, not quarters, getting their cost structure down in line to what we see on our legacy Montney assets of around $500 a foot. So we'll be working to do that. We'll be using our completion designs and technology, so be thinking plug-and-perf, simulfrack, wet sand, all of those things should help with the cost, but we'll also be looking at performance. I think it's probably a little aspirational, though, right now to say that we could get all of that growth from the additional asset without it costing some capital. We're talking about one to two incremental rigs here, so that would be on top of the six rigs that we're already running on our legacy acreage in the Motney. So I feel really encouraged, but we're going to take a little time to get the costs in line. And then, again, we were not counting on production uplift here. We're counting on delivering similar production to what they're doing, so any production uplift we see over time would be upside.

Thank you. Okay. Thanks so much, guys. Appreciate it.

Yeah, thanks, Doug.

Your next question comes from Gabe Dodd with Truist. Please go ahead.

Thanks, Operator. Hey, Brendan and team. Thanks for taking my questions. Back to 27, I guess, not to beat a dead horse, but if I just think about your budget this year, Two, three at the midpoint, 200 million or so extra for the... One Logan rig. What would inflationary pressures look like on that 2.5 as you move into 27? And then I guess on the volume side, if your new run rate is like 2.17 on crude and C5, if you were to grow that, what level of growth would you be interested in, Brendan?

Yeah. Hey, Gabe. No, it's a great question. I think the level of growth we are thinking about today is that low single digit top line and then using the buybacks to top that up into the upper single digits. But that's a framework that we think works well in this period of, I think we would refer to it as price volatility. And so... That's how we're thinking about it today. We're obviously studying your question very carefully as we make those decisions. I think from an inflation perspective, we feel good about what we've done to contract work for 2027. We are well ahead of the normal schedule. We advanced that work earlier this year, and we're glad we did, and we're just going to watch and see how things evolve over the last couple of months of 2026 here as we head into 27. But we feel good about how we've defended ourselves against inflationary pressures so far.

Got it. Thanks, President. That's helpful. You're obviously doing a great job there. And then as a follow-up, just updated M&A thoughts. You've been pretty active in the Motney and attractively adding locations relative to what the per-stick math kind of shows in the Permian. So I guess we'd be curious on a go-forward basis. Should we think about if it's continuing to look at money opportunities and maybe Permian is just more ground game and large-scale acquisitions may be priced out at this point, just given where prices have moved? We'd love to get your perspective on that. Thanks, Brendan.

Yeah, that's great. Yeah, it's a great question. I think the posture change we went through earlier this year after we closed the NuVista transaction was to shift from… The last number of years where our strategic posture was we felt important to grow our inventory life into this best-in-class spot, we shifted that into a sustainment mode and to say, okay, we've created this best-in-class inventory life in the two highest-return basins. Let's sustain that as we go. And so we came into the year with that kind of perspective. And we really take a full cycle return look to this. We've mentioned that a couple of times in the prepared remarks that it's extremely important to generate those superior returns relative to the industry and relative to the broader market. And so when we look at transactions, we look at it through that full cycle return lens, and we put ourselves into this position of strength. And so we've been opportunistic. Now, a number of opportunities have broke our way this year, which I'm thrilled about. I think we've done a series of both ground game as well as the Logan-Bolton transactions in both the Permian and the Montany to really over-sustain, if you will, this year. But, you know, these opportunities come when they come, and we've put ourselves into a position of strength to be able to execute on them. So that's our mindset. It's sustainment, and then full cycle returns create the discipline in the market.

Thanks, Brendan. Really appreciate that. Yeah, thanks, Gabe.

Your next question comes from Neil Dingman with William Blair. Please go ahead.

Good morning, Brandon, team. Brandon, my first question also on the botany, specifically, though you and Corey have talked about this and even Greg, how actively are you all today looking to restructure existing marketing contracts there, given your certainly dominant position up there? And, you know, what would the timing and potentially scale this restructuring look like?

Yeah, the products we're producing in the Montanita condensate is well set up to achieve the premium pricing that we've painted. And then I think what you're talking about, Neil, is more on the gas side. So our approach on the gas side has been to pursue diversification of market. And in Western Canada, that's largely a market access game. And so our team's done a great job of, you know, finding every available opportunity to get our gas priced into different market hubs. And so today that's... Over 80% of our production as a result, and so we're just going to continue down that path. We believe that's not only been the right strategy for the current environment, we think that's the right longer-term strategy, too. So, combination of LNG, you know, we've got our CDER project that's advancing well, and we're pleased with. We've got a number of discussions underway around, you know, in-basin demand centers, whether that's... At data centers or new pet chem demand, those are opportunities we're going to look pretty hard at and we think are actually the most obvious supplier of gas into those projects. So it's really a market diversification strategy, and it's working for us. That makes sense.

And then my second question, maybe for you or Greg, just on OFS inflation, specifically, do you all believe, you know, you're operating, you continue to have a lot of operational efficiency, especially in the PERM. I'm just wondering, can these continue to offset the inflation well in the next year? Or, you know, would you even consider, I guess, today locking in any other long-term rig or frack contracts?

Yeah, Neil, well, I mentioned before we've advanced in time. Supply chain work for 2027, and so we have locked in a number of those services probably earlier than usual, and that was because we foresaw volatility in the market and the potential for some inflation pressure, so I feel really good about that. I think we'll continue to make sure we can mitigate the impacts. We just don't know exactly how severe an inflationary pressure could be in 2027. We all remember 2022 pretty acutely, so we're conscious of, you know, what we don't know, but we've certainly done, you know, everything we can to be prepared for that as we sit here today.

Perfect. Thank you. Yeah, thanks, Neil.

Your next question comes from David Dekelbaum with Stifle.

Please go ahead.

Thanks, Brandon. Thanks for taking my questions. I wanted to just ask on the Logan side, as we get into next year, cognizant of some of the issues going on at Albright, when you contemplate that second rig, Is that a scenario in which that would be capital that otherwise would go to, you know, wells within the Albright area? I guess as I'm thinking about 27 and capital efficiency, is some of the strategy with Logan to provide some optionality where you would be directing capital away from some of the existing Montney footprint where Albright is impacting operations?

Yeah, David, I appreciate the question. You know, the approach we took with Logan was really rooted in the fundamentals of the resource and also the infrastructure and the growth capacity that it has associated with it. I think the side benefit to this current situation is that it does provide some operational flexibility and allocation flexibility. So we will absolutely use that if it makes sense. And, you know, it's part of the thing we like about both our position in the Montany and the Permian is we have a lot of flexibility to move activity around and read and react to different constraints, whether that's a midstream constraint or otherwise. So it is a part of our strategy, and we'll certainly use it if it makes sense.

Appreciate that. And maybe just to follow up to stay just north of the border, you talked about underwriting, obviously, the Logan deal around the Motney. You're bringing on some Duvernay assets or inheriting some Duvernay assets. Is there an intention to kind of figure out what you all have there? Is that something that might show up in the 27 program? Or do you intend to just sort of be observers around industry activity and perhaps think about that asset longer term?

Yeah, David, I mean, we know the DuVernay well, having previously operated position in the core of the play. When we evaluated Logan, we, of course, looked at the Duvernay acreage that they have. We did not place any value on it in the transaction. It most certainly has value, so our team will kind of look at the best way to surface that and access it for our shareholders over time here, but we were focused on the Motney. That was the reason for the deal and where we attributed value in the work.

Very clear.

Thanks for the responses. Yeah, thanks, David.

Your next question comes from John Ennis with Texas Capital. Please go ahead.

Hey, good morning, all, and thanks for taking my questions. For my first one, on the last call, you mentioned the technology from your Permian Operations Control Center had been transferred over to the Motney and gave some airtime in the prepared remarks today just on the benefits you're seeing from AI and automation. My question is, how broadly has that technology now been deployed in the Motney, and are you beginning to see measurable improvements like those achieved in the Permian?

Yeah, absolutely, John. Yeah, I'd love the question. Look, we are early innings. I kind of call this the frontier of the stacked innovation model with AI, and we're applying it across the portfolio. We generally have categorized our AI efforts into four different buckets, the first of them being safety. The second piece being digital labor, how do we become more efficient and effective? And then the third one being complex problems, and then the fourth being cyber defense. And so it's really this complex problem solving that we think has the most value from an earnings growth potential. So when you think about how that's unfolding in our operations today, it is absolutely having a free cash flow effect already. We're very active on the drilling side with AI technology optimizing our drilling efforts. We're very active in the completion space using real-time AI work to not only impact costs of completions, but also the productivity of our wells. And recovery factor. And then finally, the category that you mentioned, which is the production operation space, where every single well and facility in our footprint today runs through our digital-enabled operating control centers. Part of the thing we love about the Motney Permian model is that the technology transfer back and forth between those assets is very active today and creating real synergies within our own portfolio for our investors.

I appreciate all that color. For my follow-up, I think the first operated Barnett well in Martin County is expected online later this year. I was just curious where that well stands today, and have you seen results from either this or offset wells that would move you beyond the 1-2 well appraisal pace for 2027, and with the understanding that your Barnett acres are held by production? Thanks.

Yeah, I'll set Greg up here for the details, but the way to think about the competitor activity, we've got 100,000 acres in the barnet here that's all held by production, so we don't have an expiry motive to accelerate our activity. At this point, the big thing we're watching from competitors is the cost achievements and de-risking the cost curve. And so we're excited about the progress that our competitors are making there because we know we can match or exceed that cost performance ourselves. On productivity, I think the results are standing for themselves. It's looking like a very exciting zone with really high productivity results. So I'll turn it over to Greg to talk about where we're at with our program.

Yeah, thanks, Brendan. Yeah, we drilled the well there in Martin County, courted, very pleased with what we've seen so far. Completion is slated for later this quarter, so we'll have that well, you know, completed and coming online right around the end of the year, so it'll be a little bit of time before we get production results, but everything's gone really smoothly so far, and we're encouraged. The other thing I would add to Brendan's remarks that we're looking for, you know, we're at a unique, we have a unique opportunity in the Barnett of being able to sit back and watch not only the. The cost curve and the type curve get de-risk, but also the spacing. That's something I think is really important in this play. So we're going to sit back and watch as those three things evolve so that when we go to work to execute on our position that's already held, that we can do it in the most efficient way. So today, we're not saying exactly what we'll do in 27, but that one to two well sounds like the right ballpark as we continue to watch industry. And then when we do go to development mode in the Barnett, we can do it in the most efficient way to develop the resources.

Got it. Thank you. Thanks, John.

Your next question comes from Philip Jungwirth with BMO. Please go ahead.

Yeah, thanks. Good morning. As a leader in surfactants, is there any reason you think this could work better in the Permian than other basins? I know you're trialing it in the Motney, and you've operated many of the other lower 48 basins over your history, but just curious how much you think geology drives surfactant success, and it could be tougher to replicate elsewhere. And then separately, others with less history have talked about variability of results. So just wondering how your range of outcomes has narrowed over time and if you're better able to predict success in the Midland.

Yeah, Phil, great questions. I think the surfactant story has been one here of a very careful work in the lab to really high grade the chemistries that are going to give the maximum effect in the field. And then also that lab work also lets us tune the entire fluid system for that maximum effect. So it's not just the surfactant on its own, but it's also how it interacts with the rest of your frack fluid system. So that's been the story of success here is very deliberate. I made, I made, I think, a big point in the prepare to mark. About private data, and so a very deliberate. Um, approach, uh, data-driven, and then, uh, you know, unleashed at scale in the field and, and, and built scale relatively quickly. So that's been the story. I think, does it work across basins? Absolutely. The principle, um, applies. And, and we had done a fair bit of surfactant work in some of those basins that we are now no longer in. So we have that, we have that knowledge. And I, I would attest confidently that, that it, it does work in other basins. I think in the Motney, we're early days on proving that up with our field data, but the lab data is... It's constructive and gives us a belief that we'll find some incremental uplift there. Yeah, I think that's the direction we're taking with surfactants. As to the variability of outcome, I think we see a normal distribution of outcomes that we see with any of these technologies that drive recovery factor. And so that's why we've been, you know, so forthcoming with the data to show, you know, over 300 wells, 9% uplift in aggregate. Certainly, there's a distribution of outcomes across that set, but no more than we would expect.

Okay, great. And then I know you have a lot of runway in the Permian and have been active on the ground game. It did look like you might have built a position in Dawson County up north based on the acreage map. We've seen some others active in this area over the years. Just wondering what maybe drew you to this part of the basin and what you'd be looking to target in terms of zones or looking to do differently than what other operators have in the past.

Yeah, I'll take that one. You know, one of the exciting things about the northern part of the Midland Basin is geology starts playing a greater factor. You do have a little less fewer zones that you're chasing there. The Dean is quite attractive. Some of the sprayberry zones are attractive, but you have to have a good geologic understanding to be successful in that part of the play. We feel like our team has that understanding, and that's what gave us the confidence to add to the position in that area. But we'll be using everything we've learned over the Midland Basin to go to work up there, but it will be fewer zones, and it will be in those shallower zones today.

I would say, you know, Phil, adding to that, this is the private data story. You know, when you've got high-fidelity data on, you know, almost half of the horizontal wells that have been drilled in the basin, this gives us the information edge to be able to confidently, you know, step into these areas, and, you know, we see a lot of great potential in that part of Dawson County.

Yep, that makes sense.

Definitely a differentiator. Thanks, guys.

Thanks, Phil.

Your next question comes from Kevin McCurdy with Pickering Energy Partners. Please go ahead.

Hey, good morning. Thanks for taking my questions. A lot of good answers today. Maybe I'll throw another one on inflation. You guys touched a little bit on this earlier, but just kind of curious as a two-basin operator in two different countries, if you had a view on the difference between the The inputs and the service costs in the two different countries. And do you see an advantage in one place or another?

Yeah, Kevin, I mean, they always rhyme, but the trend we generally see, and I don't expect it to be different this time, is the flywheel spins up faster in the U.S. and then spins down faster in the U.S. So, you know, what I mean by that is. When the market is inflating, it tends to inflate a little quicker in the U.S. basins than in Canada. And then on the flip side, when the market is deflating, it tends to deflate a little quicker in the lower 48. So I think that's probably a dynamic that continues, but it's not a huge difference between the two. And so today, we're not allocating capital any differently because of...

I appreciate that, Brendan. And my follow-up is on sulfur. You mentioned that the issues for the Albright plant was a sulfur leak, but that didn't seem to affect your sulfur uplift in 3Q. Maybe you can give us a little bit more color on that market, and does the plant affect uplift, and how long do you think that lasts?

Yeah, the plant effect, the plant downtime is quite small. I mean, we're obviously seeing a little bit of production outage as a consequence. We outlined how we're working to minimize that, but that would be the only read through to our sulfur revenue would be got a little bit less gas production, so therefore a little bit less sulfur to sell as a consequence. Here, a question on the broader markets. This is a global effect of the disrupted flows coming out of the Persian Gulf, so a lot of the global sulfur production comes out of that region, and of course, that has been quite disrupted since the spring on and off, and so that's what's bleeding through into a higher global sulfur price and a higher realized sulfur price for us. So, um... It appears to us that in the fourth quarter that premium pricing is still intact, but it's priced not as premium as it was in the third quarter. So that's $75 million of incremental free cash flow in the third quarter. Some portion of that we'll still see in the fourth, but it'll be a little more muted based on what we're seeing from market prices thus far.

Appreciate that. Thank you. Yeah, thanks, Kevin.

Your next question comes from Noah Hungness with Wells Fargo. Please go ahead.

Morning. Thanks for getting me on. I was wondering for my first question here is just on capital returns. You know, you guys have seemed to have taken a bit of an above, all of the above approach, but it has been a while since you guys have increased the base dividend and, you know, you continue to grow free cash flow per share. So I guess what are your latest thoughts there as well?

Yeah, it's a great question, Noah. I think... Look, we've clearly got the incremental capacity in the business to increase the base dividend. You're absolutely right. Thus far, we've chosen to put those incremental dollars into buybacks and the ground game and debt reduction. But clearly, we have the capacity to increase the base dividend. It is, of course, a sign of a healthy, growing business to do so. So I think it's something we consider with our board every quarter and we'll continue to look at.

Okay, that's helpful. And then when we're thinking about that potential second rig on the Logan Energy assets, should we be thinking that would be on the Simonette acreage or the Pousse-Coupé acreage or maybe a blend between the two?

Yeah, I'll let Greg take that one.

Yeah, thanks for questioning that. Yeah, it's a little early to say, but probably would split activity between the two. We're just, you know, getting our arms around exactly what plans will look like. But yeah, there's opportunity we could put a rig to work in either or both.

That's helpful. Thank you.

Thanks, Norm.

Your next question comes from Jack Kavanaugh with Goldman Sachs.

Please go ahead.

Good morning, team, and thanks for taking my question. In the opening remarks, you highlighted the differentiation the company has in private data in the Permian. So I was wondering if you could quantify any of the impact on how you're seeing this driving increased productivity or other efficiencies from the Permian program relative to some of the other innovations, and then also to kind of get a better understanding of the moat you talked about, just kind of is it easily replicable and why or why not?

Yeah, Jack, for sure. And I should say this is a strategy we've pursued across the portfolio, so the same goes in the Monty. The idea here is that every decision and choice we make, whether it's a design choice on how we're going to do surfactants, whether it's a strategic choice on how we're going to allocate capital, The fundamental input to those decisions and the quality of those decisions rests on the data that you're doing your analysis upon, and so we've given our team. You know, a durable advantage here by creating what we think is a very unique and comprehensive data set to work off of. And the key part here is the high fidelity. So with public data, you just don't get the daily fidelity. You don't get things like flowing pressure and so on that really inform these decisions in a much more convincing way to establish causality. And so that's the premise of what we're doing. How is it showing up in our results? You know, always hard to pick out the specific causes, but look, you know, leading oil productivity in these two basins, that is very hard to achieve. These are very good companies that we compete against every day, and I'm very proud of what we've been able to do there, and then same goes on the cost side. So I think it's showing up in the bottom line. I think it's a part of everything we do because it's a part of every decision that we make.

Got it. That makes a ton of sense. Appreciate that color. And then for my follow-up, you know, it would be great if you could talk through slide 16 a bit more on the 10-year opportunity with, you know, the oil sands growth. Can you walk through just kind of how you see Oventive participating and kind of just how you're thinking about the capacity your Motney asset has to potentially grow into this opportunity over time?

Yeah, absolutely. So, I mean, we're going to directly participate in any condensate pricing strength from here because we've got, you know, the most exposure to that of any operator in Canada. And then we obviously have options go forward in terms of whether we add barrels into that market, whether we grow into it. So that's the participation. So it's very direct participation in that upside. And then Today, we're already seeing some impact of that on states pricing about 105% of WTI as we sit here today. So, I think it's a macro story that's emerging and one that we're following very closely.

Thanks, Tim. Yeah, thank you, Jack.

Your next question comes from Travis Wood with NBC Capital Markets. Please go ahead.

Hey, good morning, guys. Thanks for getting me on here. I might have missed this in the opening remarks, Brendan, so you can tell me to go read the transcript if you've already tackled this.

You're all good.

And yeah, thanks for bringing Canada to Midland. And I think the takeaway from that was you guys are doing substantial work on scale and both subsurface, but interestingly, above surface, both from a sand and water perspective. Could you help us understand, using that as best practice, what that could mean for the Motney program in terms of efficiencies and appreciating you're already leading Canada on a capital efficiency basis across the Motney, but what type of rate of change could we see on margin expansion or on the capital size on an efficiency measure across the Motney, If you leverage those same types of efforts on the margin.

Yeah, Travis, yeah, appreciate the setup, and yeah, thanks for joining us on that field tour in the Permian. I think the opportunity in Canada is big. We've got a lot of white space here. Greg highlighted some of the recent pacesetters that are, you know, in some cases. More than twice as efficient as the current average in the Montany. So a lot of upside room for things like Samofrac and domestic wet sand, which were really just at the early innings on deploying in Canada. So, yeah, we're excited about the upside here. And, you know, today that looks like the sort of efficiencies and offsets to inflation that Doug was asking about earlier. Thank you. But obviously, it's a long-run game that's going to unfold over a number of years here. But I don't know, Greg, if you want to add any comments about what we're seeing for Montney Pacesetters.

Yeah, I think all I would add is, you know, it really is the stacking of innovations that's allowing us to do this in Canada. Being able to do simulfrack and wet sand, you know, simulfrack alone can take $10 to $20 a foot off your cost. Wet sand has a similar impact. So we're in early stages. There's some infrastructure that's got to be built out, but we think it's going to just further our lead on costs in Canada, and so we're pretty excited about that.

Okay. I appreciate that, guys. Thank you. Thanks, Travis.

At this time, we have completed the question and answer session, and I would like to turn the call back over to Mr. Verhais. Please go ahead.

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

Thank you for your participation. You may now disconnect.