OVV Q3 2026 earnings call transcript, November 4, 2026

Good day, ladies and gentlemen, and thank you for standing by. Welcome to OVINTIV'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. For members of the media attending in a listen-only mode today, you may quote statements made by any of the OVINTIV representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Aventive. I would 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 Aventive.com. Please take note of the advisory regarding forward-looking statements at the beginning of our session. and in our disclosure documents filed on EDGAR and CEDAR+. 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. To be clear, competitive advantage is emerging for companies like ours that have best-in-class assets, a clean balance sheet, access to premium prices. And a demonstrated execution advantage that translates to superior and durable returns. That combination of attributes is true. 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 set, have created a distinct enterprise advantage that is showing up in our bottom line. Our cash flow... ...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 corridor 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. ...for 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 Motney 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... ...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 Moni 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 to 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...

...developed, 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. 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 7. 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... 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 Monty well costs.

The savings will come from faster cycle times, drilling longer laterals, domestic wet sand, simulfrack, and streamlined well-site facilities design. The balance of the synergies is about five... 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... We expect the Logan 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 prices. When we pair our unique ability to secure inventory with our stacked innovation execution, the combination is creating a clear competitive advantage for Oventive. 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. 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. 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 Motanyi because we have captured a long run. We have a 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 advantage data set with our expertise and our culture of relentlessly stacking innovation together, we get exceptional results. Our proprietary data set underpins our stacked innovation model, helping us accelerate success. innovations, avoid unsuccessful ones, and train AI models that optimize technical and operational execution. Quite across our portfolio, these insights are improved. 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 a 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. Porter 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. 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.

Montney oil and condensate volumes came in at 70... 7,000 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 money 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 repurchase 109 million dollars 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 our ongoing commitment to managing our balance sheet in a value-enhancing way our net debt balance at the end at quarter end was about 3.4 billion dollars the increase from the end of the second quarter reflects the cash outflow for our Permian and Monty 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 four million four billion dollars although we have not re-established a net debt 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 dollars of capital from the money 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 dollars consistent with the last two quarters aside from a slight increase to our expected ngl volumes our full year guidance remains our oil and condensate guide of 210 to 212 thousand barrels per day remains intact if you recall last quarter we raised our oil and condensate guidance by about two thousand barrels per day this was driven by operational efficiencies with no additional activity when we combined that with our share buyback since march 1st of approximately five percent of our total shares outstanding this equates to an annualized per share oil growth of about six percent when we factor in our fourth quarter plan buybacks this jumps to impressive eight to nine percent 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 all 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 and I'll turn the call over to Greg who will speak to our operational highlights thanks Corey capital efficiency

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 from some very strong we're brought online earlier in the year continue to dominate our year-to-date actuals our team continued to establish new pace centers in the quarter by drilling our fastest ever 15,000 foot ladder 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 or upon 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

our permeant 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 dollars of capital from the motney 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 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 including our development and reoccupation strategy the use of custom surfactants or completions and our enhanced stage architecture design our base production is also outperforming year-to-date and we expect to see a three percent 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 permanent operations control center where the team is using AI and automation to automate to optimize artificial lift parameters this is technology we imported from the money and we are now seeing the benefits across the portfolio shifting over to the money we continue to see strong year-to-date well performance which is exceeding our 2026 type curve however

the condensate volumes came in below our guide this quarter due to higher than expected Canadian royalties and an unplanned outage of a third-party operated midstream plant the Albright plant went down in July due to a leak in its 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 price has 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 years 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 pricing with the assumption of continued plant downtime we expect our fourth quarter motany condensate volumes to average 75 to 80,000 barrels per day The economics of our motany program are dominated by high-value condensate our gas realizations at a hundred and ninety-three percent 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

For more information visit www.fema.gov 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 dollars 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 money 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 average 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.

We are also starting to trial surfactants in the Motney 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 a 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 Motney peers simply do not have. It's a huge advantage for us and it's helpful. to help us secure our position as the undisputed leader in the play. I'll now turn the call back to Brendan. Thanks, Greg. I'd like to touch on the robust funding.

This is a fundamental outlook that is developing for longer-term condensate demand in Western Canada. In fact, we've never seen a more favourable set-up. 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 one million to three 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 to 500. 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. Condensate will continue to realize strong pricing for many years to come.

2026 has already been an exceptional year for OVENTIV. 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 percent 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. and our ability to deliver. OVINTIP combines best-in-class assets with unmatched execution excellence and disciplined capital allocation. We are one of the most opportunists. and we are very excited to be operating from this position of strength.

This concludes our prepared remarks. Marissa, we are 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 one. We will now begin the question and answer session and start with our first caller. Your first question comes from Scott Gruber.

Well, if you, if you did two, though, that 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. Um, and that would probably create growth in the, in the marnier oil production. Okay, great. Um, and then you, yeah. Yeah. Okay. Um, and then you, you mentioned, you know, um, you know, looking at, uh, kind of low single digit, uh, type growth and. You know, what we just discussed on, on adding incremental rigs to, to Logan would help propel that, uh, in the Monty, just maybe some color and how you're thinking about, um, you know, delivering some growth Monty versus. Permian is the Canadian backdrop here in the, in the Logan acquisition, you know, leading you to, to kind of lean in on, on the Monty over the, the Permian, or would you, you know, look to, to grow both assets in the past you've talked about. Kind of a balanced approach to growth if you go down that route. So just, you know, one of your, your latest thoughts now. Yeah. Yeah, I think sitting here today, Scott, we're still in the balanced mindset. We have the flexibility to, to, to bias one way or the. Other depending on what signals the, the macro and the, and the returns are telling us, but at least in the band of, 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, the approach to growth we've been taking is create low single digit top line.

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 a eight to nine percent 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.

This question comes from Arun Jairam with J.P. Morgan. Please go ahead.

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 allocated, you know, kind of reallocated 50 million from the Motney to the Permian to mitigate the impact from the Albany. The Albright, third-party Albright plant, you know, kind of, 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 can, I'll set Greg up here. I think he's. About the details. You know, I think on Albright, there's, there's kind of two ways this is going to go. The plant returns to production in, 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, 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. And they're continuing to find ways to adjust our activities and reroute the gas to other outlets. And 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.

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. 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 to the Permian where, you know, the team has been doing a great job operating year to date. Our drilling performance was a little ahead of schedule. So. 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. 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. Your next question comes from Josh Silverstein with UBS. Please go ahead.

Yeah, thanks, Josh. Yeah, it's 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... The first thing I'll start with is 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. I'm 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. to more than double that oil production. We have gas take away that will allow that as well. So think about it as taking a 7,000 barrel a day asset. You can 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 thinking that is keeping it at seven. And then we could add a second rig at some time during the year to grow that next year. But really excited about the asset and the opportunity that 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, to 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 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 one 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 in Wapiti positions, which compete very favorably. You know, the oil per foot there is in line with what we see down in the perm. 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. 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 Motney. 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 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 some drilling.

We could easily convert more of that inventory over to our base inventory. So a lot of opportunity there. OK. Thanks, Josh.

Your next question comes from Doug Leggett with Wolf Research. Please go ahead.

Pace setter results in both the Monty and the Permian on 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 but obviously a little bit of water to come under the bridge on how the service pricing evolves into 2027 before we get definitive. I appreciate that. I hate to come back to a question that might have already been asked or at least 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 excess infrastructure. And if you close the gap 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.

Yes. Well, first off, you know, the first thing we're going to do when we get control of the Logan assets 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 Monty 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 Monty assets of around $500 a foot. So we'll be working to do that. We'll be using. Our completion designs and technologies to be thinking, you know, plug and perf, simul frac, 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 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. Okay. Thanks so much, guys. Appreciate it. Yeah. Thanks, Doug.

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

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 mass kind of shows. Permian. So I guess we'd be curious on a go-forward basis, should we think about if it's continuing to look at Motney opportunities and maybe Permian is just more ground game and large-scale acquisitions, maybe price. Doubt 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... 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 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. 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've 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-Bolt-On transactions in both the Permian and the Montany. Over-sustain, if you will, this year. But 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. 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.

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 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 our 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 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. We're conscious of what we don't know, but we've certainly done everything we can to be prepared for that. here today. Perfect. Thank you. Yeah. Thanks, Jim. Your next question comes from David Dekelbaum with Stifle. Please go ahead.

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, so 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. Access it for our shareholders over time here, but we were focused on the money. That was the reason for the deal and where we attributed value in the transaction. In the work. Very clear. Thanks for the responses. Yeah, thank you. Your next question comes from John Ennis with Texas Capital. Please go ahead.

And then finally, the category... You mentioned, which is the production operations space where every single well and facility in our footprint today runs through our digital-enabled operating control centers. And so 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 in 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 one to two 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. The barnet here, that's all held by production. So we don't have an expiry motive to accelerate our activity. And so 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 product. 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 ours.

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 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 has gone really smoothly so far. 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 cost curve and the. Curve get de-risk, but also the spacing. That's something I think is really important in this place. 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. 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 barnet, we can do it in the most efficient way to develop the resource.

Got it. Thank you. Thanks, John.

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

So we have that knowledge, and I would attest confidently that it does work in other basins. I think in the Montney, we're early days on proving that up with our field data. But the lab data is 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 over 300. Well, 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... 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... craters 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, Bill. Your next question comes from Kevin McCurdy with Pickering Energy Partners. Please go ahead.

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 you can get a little bit less gas production, so therefore a little bit less sulfur. Sell as a consequence. Your question on the broader markets, this is a global effect of the disrupted flows coming out of the... 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... It's bleeding through into a higher global sulfur price and a higher realized sulfur price for us. So it appears to us that in the fourth quarter, that premium price... ...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 will still... ...still see in the fourth, but that 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. Good 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 in 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. 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 we 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.

Our next question comes from Jack Cavanaugh with Goldman Sachs. Please go ahead.

The idea here is that you know every decision and choice we make whether it's a design choice on 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 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 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 blowing pressure and so on that 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. But look, you know, leading oil productivity in in these two basins, that is very hard to achieve. These are very good companies that we compete against every day. And 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 it's a part of everything we do because it's part of every decision that. That makes a ton of sense. Appreciate that color. And then for my follow up, you know, it'd 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 and whether we grow into it. That's the participation. So it's very direct participation in that upside. And then, you know, today we're already seeing some impact of that on states pricing about 105 percent. WTI as we sit here today. So, you know, 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.

Yeah Travis, I appreciate the setup and thanks for joining us on that field tour in the Permian. I think the opportunity in Canada is big. A lot of white space here. Greg highlighted some of the recent pace setters that are in some cases more than twice as efficient as the current average in the Montany. A lot of upside room for things like Samofraq and domestic wet sand, which were really just at the early innings on deploying in Canada. We're excited about the upside here. And, you know, today that looks like the sort of efficiencies and offsets to inflation that that Doug was asking about earlier. But but obviously. There'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 Motney 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. Costs, 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.