Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2023 second 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 Ovintiv representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Ovintiv. I would now like to turn the conference over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest. Thanks, Michelle, and welcome everyone to our 2Q 2023 conference call. This call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the beginning of our slides and in our disclosure documents filed on SEDAR and EDGAR. Following prepared remarks, we will be available to take your questions. Please limit your time to one question and one follow-up. I will now turn the call over to our President and CEO, Brendan McCracken. Good morning. Thank you for joining us. Our outstanding second quarter results continue the strong momentum we've created with our focus on execution and making better wells for lower costs. We exceeded every one of our guidance targets on the quarter. We also closed two compelling transactions that have simplified our portfolio, extended our premium inventory, enhanced our go-forward capital efficiency, and expanded our margins. I'll speak more to the progress we're making with the newly acquired Permian assets in a moment, but first, I want to touch on our second quarter results. Our production outperformance in the quarter is coming from our legacy business. The accelerated close was included with our previously issued 2Q guidance, and the new assets have performed right in line with our expectations during the quarter. Quarter was a beat across the board from production, to capital, to per unit costs. We exceeded our targets, delivered on both efficiencies and well productivity. Greg will cover this in more detail in a moment, but our oil production outperformance is the result of our completion design innovations, and our capital reductions are the result of our execution efficiency gains. As a result, we've raised our full-year production guidance and lowered our full-year capital guide. Across the portfolio, the intense focus our teams have placed on operational execution continues to deliver results, especially in the Permian, where we posted another quarter of record operational efficiencies. Our Permian team has seamlessly integrated the new assets into our existing operations. We were pleased to close the transaction early, and we have already finished resetting activity on the new acreage. We're currently at our expected run rate activity for the rest of the year, with five rigs and three completion crews in the Permian. We're also already executing our proven drilling and completion designs on our new assets, we expect to have our first fully Ovintiv designed wells online later in the fourth quarter. On second quarter production, we exceeded the top end of our guidance on oil, gas, and NGLs, while coming in below the low end of guidance for capital. These results are driven by strong well performance from each asset in our portfolio, successful base decline management on our older vintage wells, tailwinds from lower natural gas royalty rates in the Montney, and capital savings from continued record-setting operational performance across the asset base. We also returned approximately $172 million to our shareholders through share buybacks and our recently increased base dividend. I'll now turn the call over to Corey to cover our financial results. Thanks, Brendan. Good morning. In addition to the great operational results Brendan outlined, we also delivered strong financial results in the quarter, with earnings per share of $1.34 and cash flow per share of $2.79, beating consensus estimates. We remain free cash flow positive despite the impact of transaction-related costs and the incremental capital associated with the early close of the Permian Basin acquisition. We also saw a strong per-unit cost performance, with operating expense, transportation and processing expense, and production, mineral, and other taxes coming in below the midpoint of guidance on a combined basis. Operating expense also benefited from a $23 million recovery of prior year's costs. We issued debt during the quarter to finance a portion of the Permian acquisition, and we are very pleased with our resulting capital structure and the maintenance of our investment-grade rating and stable outlook from all four credit rating agencies. At quarter end, our leverage ratio is 1.7 times. This included all of the acquisition finance debts but only 19 days of EBITDA from the acquired assets. We remain committed to our mid-cycle leverage target of 1 times, or about $4 billion of total debt, assuming mid-cycle prices. The maturity profile of our recently issued bonds will allow us to optimize our debt paydown schedule as we work towards that target. While debt reduction is a big area of focus for us in the near term, our shareholder return framework has not changed. We will continue to distribute at least 50% of post-dividend free cash flow to our shareholders, with the remaining 50% going to the balance sheet. I would like to note that the amount of cash available for buybacks in our shareholder return framework is determined each quarter on a discrete basis. Yesterday, we provided our third quarter guidance and updated our 2023 full year guide to reflect the efficiencies, cost savings, and improved well productivity we've seen year to date across the portfolio. In the third quarter, we expect to see total production average 540,000-560,000 BOE per day, with oil and condensate production of 202,000-208,000 barrels per day. We expect oil and condensate production to continue to grow through the fourth quarter and average 210,000 barrels per day in the second half of the year. This reflects the production momentum from the new Permian assets as we bring acquired WIPs online. The production profile will normalize by mid-year 2024, with the second half 2024 oil and condensate production stabilizing at 200,000 barrels per day. We also raised our full year natural gas guide due to strong well performance across the portfolio. Third quarter CapEx will be the peak for the year at $840 million-$890 million. This reflects the shift from a 10-rig program in the Permian at the time the acquisition closed to our current 5-rig program, and the capital associated with the higher level of activity as we work to bring the acquired wells in progress online by year-end. We expect to bring online about 100 wells in the 3rd quarter, with roughly half of these from the acquired Permian assets. We've updated our full year guidance with higher production and lower capital investment. The new guide incorporates the operational and capital efficiencies we've achieved, our strong well productivity performance, and the success we had in offsetting base production declines. In addition to increased capital efficiency, we also expect to see increased cash cost savings. We divested a relatively higher cost asset in the Bakken and added a relatively lower cost asset in the Permian. We anticipate company-level savings of approximately 5% on a combined basis for OpEx and T&P in the second half of the year. We also provided an update to our hedging positions with the materials yesterday, with about 50% of our WTI exposure and about 40% of our NYMEX gas exposure hedged for the next 12 months. Capital efficiency is a key focus across the organization, as efficiently converting our resource into cash flow is a crucial aspect of our durable returns approach. Ovintiv's capital efficiency ranks top tier among our peers and is creating exceptional value in today's volatile commodity and macroeconomic environment. In 2024, we expect to produce more than 200,000 barrels of oil and condensate per day for about $2.3 billion of CapEx at the midpoint. That's a 15% year-over-year capital efficiency improvement, with an associated increase of 30,000 barrels per day of oil and condensate versus our original 2023 guide. This increase in capital efficiency generates higher returns on invested capital and allows us to deliver higher cash returns to our shareholder. When compared to our peers, Ovintiv's 2024 capital program will require about $250 million less capital to deliver the same production at the midpoint of our 2024 oil and condensate production and capital guides. I'll now turn the call over to Greg to cover our operational highlights. Thanks, Corey. As Brendan noted, our top priority over the last 1.5 months has been the efficient and seamless integration of the new Permian assets into our existing operations, and the team has done a very impressive job. With five rigs and three frac spreads currently running across our 180,000 acres in the play, we are already at our run rate activity for the rest of the year. Our results in the Permian year to date have been stellar, and we are very excited to unleash our proven development model on the acquired acreage. The wells on the new acreage are performing in line with average 2022 Midland Basin productivity rates, and we see opportunities to increase well performance and capital efficiency as we apply our drilling and completion approach to these assets. We have already begun deploying our proven optimization techniques on completion design, artificial lift, and accelerated cycle times on the wells that were already in progress when the acquisition closed. We are also streamlining planning and logistics across our combined Permian position, improving efficiency versus the three separate operating companies that were previously planning and executing work on each of their individual footprints. We have already reduced offset frac hits as we've optimized our program across the combined position. As Brendan noted, we expect to see our first end-to-end Ovintiv-designed wells online in the fourth quarter. Our efforts on completion design, and particularly on stage architecture, continue to deliver leading well performance across our Permian acreage. The chart on the right shows the 2022 Midland Basin industry average compared to our 2023 type curve and the wells we brought online in the first half of the year. Our year-to-date oil performance is among the highest we've ever delivered in the Permian. It's important to note that the well outperformance is the result of the advances we've made to enhance completion design, including stage architecture, fluid chemistry, and proppant loading. Our cube development approach has stayed consistent, and our program well spacing is unchanged year-over-year. These results are spread out across our acreage footprint, and our enhanced completions are being executed without an increase to completed well costs, as we are able to deploy our leading efficiencies into making better wells. While the recent well performance is outstanding, we're being thoughtful with our go-forward type curve assumptions....In the third quarter alone, we will bring on more than 50% more wells than we did in the entire first half of the year in the Permian. Once we see the results from these completions, as well as the longer-term production from the previous wells, we'll have a much better handle on the repeatable uplift we can incorporate into our forecast. I'd like to take a quick moment to recognize the outstanding performance from our team in the Permian this quarter. Our operations continue to hit on all cylinders, setting new performance records while seamlessly integrating our newly acquired assets. These results are allowing us to deliver stronger well performance through completions optimization and improved wells, improved stage architecture in a cost-effective manner. For example, our second quarter average completion speed, at well over 3,500 feet per day, is about 40% faster than our average speed over the last three years and 11% faster than our first quarter average. Using the same time frame comparison, we now pump 80% more proppant per day and 45% more fluid. Our enhanced performance is delivering better wells at lower cost, improving our capital efficiency. We continue to deliver impressive results across our portfolio, our year-to-date performance in the Montney is no exception. Ovintiv wells continue to dominate the list of most productive wells in the play on a total BOE basis. Over the last 12 months, we have brought on the top 31 wells in the Montney and 36 of the top 50. I want to be clear that these impressive production rates do not come with a higher price tag. The average cost of the 36 wells highlighted in the chart was $4.5 million per well, making Montney wells the lowest cost in our portfolio. The great returns we generate in the play are further enhanced by our market diversification strategy, which we use to manage flow assurance and price risk. With almost all our Montney gas pricing outside of AECO, we realized 97% of NYMEX on a pre-hedge basis, and our condensate received 96% of WTI during the quarter. In the Uinta, we continue to deliver some of the strongest oil well results in North America. We recently brought on our three-well Jorgensen pad in Duchesne County, with strong IP30 rates of 1,850 barrels of oil per day per well. Our large contiguous land base of approximately 130,000 net acres has multiple benches with about 1,000 feet of collective pay. It is 80% undeveloped, which translates into a significant inventory runway. As we previously noted, we recently secured additional rail capacity to the Gulf Coast, and we currently rail about 30%-40% of our volumes there. This scalable option supports our future development plans for the play. Due to the highly oily nature of this play, in the first half of the year, the Uinta tied the Permian for the highest operating margin in our portfolio. Given the current gas and NGL markets, we have reduced our activity in the Anadarko Basin in the back half of the year. That said, the Anadarko is expected to be our top free cash flow-generating asset in 2023 and remains a premier multi-product option in our portfolio. The team continues to work the asset hard, cutting our base declines in half since 2021. They also wrapped up this year's activity on a high note, realizing a 25% increase in drilling feet per day in the quarter versus our 2022 average. I will now turn the call back to Brendan. Thanks, Greg. Before we move to Q&A, I'd like to sum up the key takeaways from today's call. I'd like to commend our team for the outstanding results year-to-date. Our focus on execution excellence has shown up across our portfolio. We have successfully integrated the new Permian assets, and our team is already applying our development model to the wells in progress. The asset performance has been strong, and we see opportunities for further gains going forward. We're increasing full year 2023 production guidance and lowering capital spending. We are one of the most capital-efficient operators in the industry, and our 2024 program is advantaged compared to our peers in its ability to deliver more barrels for fewer dollars. We are committed to debt reduction while returning significant cash to our shareholders. Our shareholder returns framework remains unchanged, and the amount available to shareholders will be determined by the same reliable approach every quarter. Over the long term, we believe that value creation in the E&P space will come from companies that can durably generate both superior return on invested capital and return of cash to shareholders. We are well positioned to deliver on this value proposition with a deep premium inventory, leading capital efficiency to convert that inventory to free cash flow, and the disciplined capital allocation to make sure those returns flow through to the bottom line and to our shareholders. This concludes our prepared remarks. Michelle, we're now ready to open the line for questions. Thank you, sir. 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 go to the first caller. Your first question comes from Arun Jayaram at JP Morgan. Please go ahead. Yeah, good morning. Brendan, I was wondering if you could shed more insights on just the well productivity gains that you're seeing, you know, particularly in the Permian. You know, Greg mentioned stage architecture, fluid, and completion design. I was wondering if you could give us more insights on, on that, the potential repeatability. I was also wondering if you've tested this in perhaps some areas outside of the core, and if you have any maybe, preliminary results to share? Yeah, Arun, good morning. Appreciate the question and the pickup on the well performance. Obviously, really excited about what we're seeing there. As we reported here today, we've now got 44 wells of the program online with production history, and the performance is, you know, well above our 2023 type curve, which we're obviously enthused about. You know, really the driver we're seeing here is the completion design piece that you mentioned. This has been a multi-year effort by our team to zero in on the true causal factors that can drive well performance and increased recovery from shale. It's not just in the Permian. We're deploying this across the whole portfolio. Really, I like to kind of break it down into three buckets, Arun, in terms of what the team's been, been driving on, and I probably won't do service to the, the, the, the detail and the, and the, you know, multiple factors that are driving here. The three buckets we see really are the stage architecture, which is, is our phrase for the combination of, of cluster design, cluster spacing, and then, of course, the sand and, and water loading that we're feeding in through those clusters. The whole point of that stage, stage architecture engineering is to get a, a more conductive fracture network, more consistently placed along the entire lateral. Of course, that becomes even more important as we drill longer laterals in these plays and, and drive efficiencies that way. That's the first bucket. The second bucket is, is kind of what we call chemistry, and that's using the chemistry of the frac fluid to try and enhance the permeability, of oil in that fracture network, and so then, as a consequence, get more recovery, from, from the, the pore system in place. The final bucket is, is really got a few things in it, but, but really it's this idea of real-time frac monitoring. The, the approach here is traditionally in our industry, the, the approach was the engineers in the office would write up a frac program and send it out to the field, and then the field would pump it. Sometime down the road, there would be a look back done and, and potentially optimization occur in, in subsequent wells. What we're trying to-- the nut we're trying to crack with technology and telemetry is to be able to do that real time and be learning from the signals we're getting back subsurface while we're pumping, and then tune our frac design as we go. As a consequence, just be more efficient with that frac design, but also get more recovery along that long lateral. Really, those are the three buckets I'd speak to, Arun. It sounds like a nice endorsement of how the SmartFleet technology, Jeff Miller. My follow-up, Brendan, is have you tested this kind of completion design outside of the core? Could there have- Yes. be any implications of, call it, Tier 2 locations on the map, you know, where you could, you know, boost the overall productivity to perhaps mimic Tier 1 type of economics? Yeah, and, and we did. If, I, I don't have the slide number off the top of my head here, but the slide that shows the Permian type curve performance also shows a map of where those 44 wells are across our land base. What you can see from that is they're spread across the land base. What that is telling us is this, these completion designs are working across the Permian for us. As far as sort of the Tier 1, Tier 2 implications, you know, really what we're seeing is it's making the Tier 1 stuff better. You know, the good news story for our acreage position is, you know, we're pretty much in the core of the basin, across the board. We've really been just using it on the acres we've got, which are really all in that Tier 1 bucket. I think your point is valid, you know, moving locations from near premium into that premium bucket is a win, and we look to do that all the time as well. You know, one of the things we've talked about on the new acres is that that 800 premium count underwrites a 3-bench development across the acreage. Greg pointed out we've got quite a number of wells in progress that we'll be bringing on stream, and those cubes are all either 3 or 4 bench cubes or even higher in some instances. You know, excited to see how those completion designs show up when we start to get them later this year. Great. Thanks. I'll turn it back. Thanks, Arun. Your next question will come from Neal Dingmann at Truist Securities. Please go ahead. Morning, all. Thanks for the time. Brendan, my first question is on your forward plan, which seems quite good. Specifically, you all talked about stable out your production, I believe. I'm just wondering, would you kind of consider this a kind of a maintenance plan? You know, if so, could you maybe speak to around the level of CapEx needed to sustain this? Yeah, Neal, appreciate it. Yeah, we, we, you know, reiterated that 2024 view here today, obviously feel good about where that is sitting as we get further and further into the year here, and now actually have control of the new assets. Continuing to feel really good about that guide. The, you know, big movers are gonna be how much deflation actually shows up. We think sitting here today with what we know about cost structure and activity levels, that guide still makes total sense to us. The implied midpoint of capital for 2024 and then settling in at that 200,000 barrels a day in the second half, make total sense. You know, the only thing I'd add to that in terms of maintenance is we continue to think that's the right way to prosecute this business. We've talked about really 3 gates of decision-making to consider around capital allocation for either maintenance or modest growth. Really, in order to even think about modest growth, the 3 gates for us would be, first, it would have to be a better cash flow per share outcome than just buying our shares back. That's the first test. Then the second test would be, you know, does the world need more barrels and more BTUs? Then the third test would be, you know, what's the execution risk on adding that activity? You know, if I just quickly run through that model here today, the buybacks still screen more favorably than adding rigs and spreads to the program. Then our judgment today is the world isn't asking for more barrels and BTUs from our company. Then, you know, the third gate there, you know, certainly that execution risk from a year-over-year perspective, feels a lot better than it did last year when inflation was running pretty, pretty hard. Still, those other two gates would have us staying in that maintenance mode. Yeah, I agree. All that, all that makes sense, certainly to me as well. My second question, maybe for Greg on the, on the Permian. Specifically, can you address, can you address future potential, maybe, frac hits or needed well shut-ins? Seems to me, you know, kind of the plan you guys have talked about even now post-deal, that you all will have a much more minimum level of shut-ins, unlike a number of your various peers that are, that are experiencing this. Yeah, Neal, thanks for the question. You're, you're exactly right. That, that was one of the, the value propositions we saw with the acquisition we just closed, was, you had three companies that were doing a good job, but operating independently, and because of that, they weren't able to coordinate schedules, and they were knocking off wells shortly after they were brought on. What we've already seen, as I've mentioned in my prepared remarks, is that by using a coordinated approach across the entire 180,000-acre footprint we now have, we've already seen a reduction in frac hits, which allows us to get the full benefit of all the fracs that we're out there pumping today while not knocking these newer wells off. We'll continue to optimize this as we go forward, but we do feel like that is a big part of the value we're gonna be able to bring to this acreage by not, not having that be a problem. Some of these new completion designs also seem to be helping on that front as well. Yeah, great to hear. Thanks, Greg. Thanks, Brendan. Thanks, Neal. Your next question will come from Gabe Daoud at TD Cowen. Please go ahead. Hey, thanks. Morning, everyone. Maybe just back to the Permian outperformance. Greg, could you maybe just comment on what exactly you need to see here, or how much time and data do you need to collect to start factoring in this outperformance on, on, or in your, in your go-forward guidance? I guess it would depend on what some of these new cubes look like on the new acreage, but curious to hear your thoughts on that. Then could you also just comment on where pro forma Permian production is today? I think at the time of the deal, you pointed to 125,000 barrels a day of oil and condensate combined. Just curious if that's more or less where you're at today? Yeah. As far as the forecasting goes, as I, as I mentioned, you know, we've got a lot of activity going on in the play today. We're very pleased with what we saw in the first half, and those wells continue to hold up, but we're gonna be bringing on a lot more wells in the back half of the year. We're gonna wanna see how that productivity holds up. Keeping in mind, a number of the wells, you know, over half the wells we're bringing online in the third quarter are gonna be wells that while we're influencing the tail end of the completion, we were not involved in those wells from the, you know, their inception to bringing them online. We do believe there's, you know, a little uncertainty there. We wanna see how those wells do. We're, you know, quickly incorporating all of our completion techniques into our operations. You're gonna see, as we go through the third and into the fourth quarter, just a whole lot of data coming in, and we're trying to be thoughtful about how we, we approach this. By later this year, we should have a much better sense of how well this uplift not only, you know, is impacting the, our existing legacy portfolio, but the new wells. It's not just the number of wells that we need to see, it's the duration, you know, how long this production uplift holds up. We're, we're looking forward to seeing that, and then as we continue to see that more consistently, we'll start baking that into our forecast. Yeah, Gabe, I think you had a question on the pro forma there, too. Yeah, as Greg picked up earlier, we've got about 60-70 Permian wells to bring on in the quarter, so it's a fairly dynamic number every any given day here. But you're right, we're running just a little over that 120,000 barrel a day at the moment. Got it. Got it. Okay, cool. Thanks, guys. That's helpful. Just a quick follow-up on the cost side. You highlighted some of the efficiencies driving savings, and you have that $2.1 billion-$2.5 billion range out there for 2024. Curious, I guess, what's embedded in that $2.1 billion? Is it... I guess, if efficiencies continue to hold, could that number trend towards $2.1 billion, or is there a little bit of expectations around some cost deflation continuing? Just, just curious if you could maybe talk a little bit more about what we need to see for that $2.1 billion number. Thanks, guys. Yeah, Gabe, no, appreciate it. I think the service cost environment is probably the bigger driver of the range there, as we see it sitting here today. And, we'll just have to see where, where service prices trend. You know, we've seen rig counts come off on both the gas and the oil side by about 15% from the peaks. You know, if that continues, then that'll keep driving further deflation and, that could push us lower in the range, and we'll, we'll just have to see. Obviously, oil has ticked up a little bit, and gas has maybe been a bit stronger through the summer months. We'll see what that translates through to activities by the rest of industry. You know, we've been clear about, we're not adding activity, but, but we'll see what happens across the rest of industry and, and tune our 2024 guide as we get closer to it. Thanks, guys. Yeah, thank you. Your next question will come from Josh Silverstein at UBS. Please go ahead. Yeah, thanks. Good morning, guys. I was just thinking about the, the shareholder return profile versus the, the debt reduction. you know, you mentioned kind of up to 50% for the for the balance sheet p-portion of it. Is the goal basically just to, you know, have enough cash on hand to pay down the 25 and 26 maturities as they come up? Or do you actually want to build a little bit more cash than that to be opportunistic for other bolt-ons or anything else? Yeah, I think, Josh, there, what we'll do is we'll, we'll follow the program here, which, which calls for the, the at least 50% to, to incremental shareholder return over and above the base dividend. Then the rest will be available for that debt reduction, which is, you know, we're trying to take the debt down to 4. So I think we'll, we'll be very opportunistic to do that as we go along, and I think we were thoughtful about the capital structure to enable that without, without extra cost. So like, like you said, we've got some well-timed maturities in the next couple of years to be able to do that. Got it. Thanks for that. Then, I know you guys do have a second report that you went to now. It seems like you have pretty good well performance there. I was curious on, on the rail infrastructure that, that you guys had mentioned. Is this supporting potential basin growth for, for you guys and increased capital allocation, or is it really just for economics? Thanks. Yeah, no, appreciate it. Yeah, we're excited about what we're seeing in the Uinta. You know, remember, the last two years, what we've worked hard to do is demonstrate well performance at cube development spacing and then unlock that market access to the Gulf Coast, made great progress on both those fronts. We're, we're now railing to the Gulf some 30%-40% of our total Uinta volumes, with the two rigs running there, we're gonna see a big production ramp in the Uinta through the back half of the year. That, that rail infrastructure is, is low cost and scalable. That'll afford us to be able to have higher Uinta production volumes through the back part of this year and into 2024, depending on, on how we set capital in 2024. Got it. Thank you. Yeah, great. Thanks, Josh. Your next question will come from Doug Leggate at Bank of America. Please go ahead. Good morning. This is John Abbott on for Doug Leggate. Our questions really are on the Anadarko Basin. First of all, you know, with the reduction of activity, what would you have to see in terms of price, prices to bring activity back there to that basin? Well, hey, John. Yeah, good morning. Yeah, on the Anadarko, you know, really, our team's done just an incredible job here. You know, the focus on innovation has resulted in a substantial shallowing of our base decline to, to 20%, and that creates a ton of value for us, means that it's set to be our highest free cash flow generator in the portfolio. The recent wells that the team had brought on stream in the first half of the year have been really strong performers. I, I mentioned earlier we've been using the same completion design optimizations in, in the other assets as the Permian, and that's, that's the same here in the Anadarko. We're encouraged by the underlying asset performance. Really, with the, you know, gas and NGL fundamentals that we saw coming into the second half of the year is, is really why we chose to rotate capital out of there for the time being. With the stronger gas and NGL fundamental into 2024, particularly, later in 2024, once we see the startup of some incremental LNG pull off the Gulf Coast, that, that could be the signal that, that, brings capital back into the Anadarko and brings the rigs back there. I think we'll just watch for it. I'm not sure there's a specific price toggle one way or the other because, you know, it's always gonna depend a little bit on cost structure as well. The team has been, you know, really working hard on initiatives to reduce D&C costs and increase cycle times in the Anadarko as well. I think it's a little bit of a combination of those things, but for the, you know, the big thing is we want to see a more healthy supply and demand balance on the gas side and the NGL side. That's very helpful. Just as a quick follow-up on the Anadarko, just given the improvements in the underlying declines and the productivity that you're seeing, you know, how long do you think you can actually do that for in terms of holding it, at how many years of inventory, and how long do you think you can actually hold that flat, potentially, if you wanted to? Yeah. The Anadarko, the fantastic piece there is we've got a, a deep, high-quality inventory in that play as well. You know, really, we see over a decade of, of drilling inventory to hold that asset flat. Should we choose to allocate the capital there to do that? All right. Thank you very much. Thanks, John. Your next question will come from Umang Choudhary at Goldman Sachs. Please go ahead. My questions. appreciate all the color on the strong performance in the Permian and the Montney, and understand that there's less clarity in terms of how the 3Q well performance will shape up in the Permian in the acquired assets. Can you remind us on the cadence of activity in the back half of this year, especially in the Permian? I'm trying to pair the improved performance, which you've seen recently in your legacy assets, and the implication to your production guidance next year. Yeah, Umang, appreciate it. Yeah, cadence-wise, you know, a lot going on in the Permian here in the back half of the year. We're gonna see between 60 and 70 tills in the third quarter and just a little bit less than that in the fourth quarter, but right up there as well. That, that's the, the setup through the back half of the year on cadence, which is gonna see us at a total company level, average 210,000 barrels a day of crude and condi in the back half of the year, and then some of that'll will spill into early 2024, and then we'd expect to level back out at that 200,000 barrels a day by midyear and hold that flat through the, through the back half. That's the cadence set up there. Got you. That's really helpful. Then, my next question was on risk management. As you mentioned earlier, you added some leverage here with the transaction. Any updated thoughts around the level of hedges, hedging you want to do, to protect yourself from commodity price risk next year? Yeah, Umang, appreciate the question there. On hedging, really what we've done here is continue to use our next 12-month approach. Building the book out 1 quarter at a time, over the next 12 months. We've also continued to use three-way structures to provide a soft floor that we're comfortable with, but also give some upside to higher price exposure, which, of course, would enable us to participate in a structurally stronger market. In the second quarter here, we did add some second quarter 2024 hedges on the gas side, so over that next 12-month period, we're about 50% hedged on oil and about 40% hedged on gas, again, primarily in those three-way structures. You know, I'm sure you saw it, but slide 20's got the, the details of that. That's generally the approach we've been taking. I think as we continue to drive debt down, we'll drive that hedging level down from that sort of 50% and 40% down back towards that more, you know, quarter to a third of production level. Got it. Thank you so much. Thank you. Your next question will come from Phillips Johnston at Capital One. Please go ahead. Hey, guys, thanks. In addition to the uplift in productivity that you're seeing in this year's vintage of wells in the legacy Midland properties, in the slide deck, you also mentioned older wells are outperforming forecasts. Just wondering what kind of magnitude we might be talking about there, what you would attribute that to, and which, which areas you're seeing the biggest upside? Yeah. Phillips, no, awesome pickup. Appreciate the, the catch on that. You know, obviously, that's one of the most efficient ways to add production is, is by optimizing base. Kind of the contributing factors here, and Greg might have some fill-ins, but it's been what we've been doing on artificial lift, and then also some, some really inexpensive workover treatments that have been, been creating, some boosts in our older vintage wells, that we're excited about. I don't know, Greg, if you wanna, wanna add anything there? Yeah, it's really just a lot of great work by the teams, blocking and tackling, you know, reducing failure frequency. But we do see a little improvement with some of the new frac designs we're pumping, seem to have less of an impact on the parent wells. But really just a lot of things that the teams are looking at that are adding up to a, you know, a nice little beat there on the base side. This is something we're focused on in all of the areas, not just the Permian. Okay. I'm, I'm guessing that's also not factored into your, your second half of the year production guidance or the 2024 guidance, correct? Well, I think what we've factored in here now is the, the performance uptick we've seen on the existing PDP. you know, where the upside is still just, you know, what further decline abatement can we do? we have included the, the PDP impacts that we're realizing today in, in the forward guide. Okay. Okay, that makes sense. Then just, maybe an update on LNG Canada phase one. I realize you guys aren't a direct participant, but it's obviously gonna help pricing in the business. I think as of the Montney day in September, I think the project was over 60% complete with timing in, first quarter of 2025. Just wondering how the progress has been since then. Yeah, I'll, I'll get Corey to chime in because there have been some recent progress updates from the operators there, both on the pipe side and the LNG liquefaction side, and he might remember the percentages. They're actually pretty high in terms of% complete here now. You know, what I'd say about LNG generally is we continue to evaluate and are engaged in all of the West Coast LNG projects that are either under construction, like phase one or pre-FID, like several others. We do think it makes sense to have some exposure to LNG for our portfolio over time. We think that's complementary to our existing price diversification strategy in the Montney. Couple, couple kind of ground rules, if you will. I think, you know, one, we're not interested in an equity stake, so I think we can take that off the board. We've shown we can demonstrate great success by developing egress out of the Montney and into the rest of North America. I think the logical extension of that is also to have a piece of global exposure here. Our team's, you know, hard at work across each of those projects to find the right commercial solution for us. I don't know, Corey, if you've got any of those project update numbers off the top of your head there. Yeah, sure, Brendan. Shell talked about this a little bit yesterday, but I think their, their reference point, certainly sounds more optimistic, than it had in the past even. They're talking about 75% complete on the midstream and more than 90% complete on the pipeline. Obviously that's, coming soon and, and good, good updates from that standpoint. Okay, that sounds good. Thanks. Thanks, Phil. Your next question comes from Jeoffrey Lambujon at TPH&Co. Please go ahead. Good morning, everyone. Thanks for taking my, my questions. My first one's another one on how you're looking at forecasting for next year. If we get to a situation where the current forecast for the Permian in particular, proves conservative for 2024, with maybe the same CapEx range, even talking about actually able to generate more production than what's modeled today, how should we think about the overall outlook potentially changing? Do you just wanna get a sense for if we should think about, you know, reductions to that spending range, maybe with less capital again, needed to still achieve greater than the 200 level on crude condensates that you've spoken to? If it might be more like a steady range on CapEx, but with the potential for volume sold closer to what we might see in Q4 here for a bit longer. Yeah, Jeff, appreciate the question and love your, love your, your take on it. You know, I think what we'll do as, as we set 2024 is we'll, we'll run those three gates, you know, on the where does it make sense from a cash flow per share impact? What's the, what's the world asking for in terms of barrels and BTUs? Then what do we see as the execution risk? You know, sitting here today, I think that maintenance level continues to feel like the right answer to those, but, but obviously we'll get a chance to look at that through the back half of the year. That'll be our starting point on that decision. Then, you know, the other piece that we'll factor into it is just the level loading. You know, we've worked really hard to create a level loaded program this year. We think that's benefiting our teams greatly, and so we'll want to be preserving that as we kinda go forward into 2024 and, and setting up for a consistent level loaded program across the assets, full year 2024. Those will be the things that we weigh as we work our way through this. Then, you know, we'll be looking to optimize the returns, both return on invested capital and the return on cash to shareholder. Okay, great. Then my second one- Yes. Just a follow-up on the Uinta, just given, you know, we're about to see some additional contribution from that asset here in the second half, as, as you alluded to. Wanted to just ask simply what you need to see to allocate more capital there. I know you've been talking about, you know, the productivity comparisons. You spoke to the infrastructure earlier, kind of making room for that, if that's ultimately where you decide to go. I think you've spoken to some depth on the, the cost side of the equation in the past, but just wanted to get a refresh there on how you're thinking about competitiveness of that asset just going into next year versus the balance of the portfolio. Yeah, you bet. Right now, the, the program we've got through the rest of 2023 here is, is absolutely return competitive with the rest of our portfolio. It's, it sits right there on the, on the same level of returns that we're seeing in the other assets. That's, that's important, first of all, because otherwise we wouldn't put capital there. You know, as far as trajectory from here, I think 2 rigs is, is gonna, you know, really see a big ramp in, in volumes there. That feels like the right level to be thinking about as we head into 2024. We'll just kind of watch and see the performance as we go through the year. Perfect. Thanks, y'all. Yeah. Thank you, Jeff. At this time, we have completed the question and answer session, and I will turn the call back to Mr. Verhaest. Actually, I do apologize. Yeah. We have one question left in the queue from Scott Gruber at Citigroup. Please go ahead, Mr. Gruber. Well, thanks for, for squeezing me in. Just a couple follow-up questions. What level of, of overall cost inflation would align with the midpoint of the 2024 guide? Just kind of ballpark. Yeah. Hey, Scott. Yeah, glad we glad we, we, we got you there. Apologize for the any confusion. Yeah, the... So really that midpoint of that guidance range would be sort of the deflation trajectory that we're seeing currently. So, you know, as we've kind of reviewed service pricing most recently, you know, we've seen a little bit of reductions on some of the cost categories like diesel and steel. We've seen the green shoots of reductions on, on other categories like rigs and spreads. So it, it's basically including what we see today. Like I said, we'll have to watch and see how things unfold if, if more deflation materializes as we go through the back half of the year. Okay. Any way to quantify that? Is it kind of a mid-single digit type number? Is it trending towards double digit? Just curious. I think, yeah, and, and, you know, so the numbers we're seeing are low single digit. The only thing I'd say about that, of course, is it depends on your starting point, for, for what... You know, I've seen other E&Ps comment on, on different numbers, and it, it always just, you know, has to be rooted in what you're starting from. We had a number of fairly favorable service pricing arrangements, in, in 2024 here, or in 2023 here. You know, what we're seeing is kind of low single digits relative to that. Okay. I appreciate the color. Thanks. Yeah. Thanks, Scott. My apologies again. At this time, we have concluded the question and answer session, and I will turn the call back to Mr. Verhaest. Thanks, Michelle, and thank you everyone for joining us today. Our call is now complete. Ladies and gentlemen, this does conclude your conference call for this morning. We would like to thank everyone for participating and ask you to please disconnect your lines.