Ovintiv Inc. (NYSE:OVV) Q2 2023 Earnings Call Transcript

Ovintiv Inc. (NYSE:OVV) Q2 2023 Earnings Call Transcript July 28, 2023

Operator: 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. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Ovintiv. I would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.

Jason Verhaest: Thanks, Michelle, and welcome, everyone to our second quarter ’23 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.

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 are 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’ve already finished resetting activity on the new acreage. We are currently at our expected run rate activity for the rest of the year with 5 rigs and three completion crews in the Permian. We are also already executing our proven drilling and completion designs on our new assets, and we fully expect — we expect to have our first fully Ovintiv design wells online later in the fourth quarter. On second quarter production, we exceeded the top end of our guidance on oil, gas and NGLs were coming in below the low end of guidance for capital. These results were 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.

Corey Code: Thanks, Brendan, and 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 was 1.7x, and this included all of the acquisition finance debt, but only 19 days of EBITDA from the acquired assets. We remain committed to our mid-cycle leverage target of 1x 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 pay down 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 to 560,000 BOE per day, with oil and condensate production of 202,000 to 208,000 barrels per day. We expect oil and condensate production to continue to grow through the fourth quarter and averaged 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 midyear 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 capital spending will be the peak for the year at $840 million to $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 third 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.

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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 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 in 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 shareholders.

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 will now turn the call over to Greg to cover our operational highlights.

Gregory Givens: 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 5 rigs and 3 frac spreads currently running across 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 were spread out across our acreage footprint and our enhanced completions are being executed without an increase to completed well cost. As we are able to deploy our leading efficiencies into making better wells.

While the recent well performance is outstanding, we remain 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 will 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 continued 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 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 3 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, and 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 3 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 as 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% to 40% of our volumes there. This scalable option supports our future development plans for the play. Due to the highly oily nature of display 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’ve 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 multiproduct 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.

Brendan McCracken: Thanks, Greg. And 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 are 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 are now ready to open the line for questions.

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Q&A Session

Operator: [Operator Instructions] Your first question comes from Arun Jayaram at JPMorgan. Please go ahead.

Arun Jayaram: Yes. Good morning. Brendan, I was wondering if you could shed more insights on just the well productivity gains that you’re seeing, particularly in the Permian. Greg mentioned stage architecture, fluid and completion design, but I was wondering if you could give us more insights on that — the potential repeatability. And 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.

Brendan McCracken: Yes. Arun, good morning. I appreciate the question and the pickup on the well performance. Obviously, really excited about what we are seeing there. And as we reported here today, we’ve now got 44 wells of the program online with production history and the performance is well above our 2023 type curve, which we are obviously enthused about. Really, the driver we are seeing here is the completion design piece that you mentioned. This has been a multiyear effort by our team to zero-in on the true causal factors that can drive well performance and increased recovery from shale. And it’s not just in the Permian, we’re deploying this across the whole portfolio. And really, I like to kind of break it down into three buckets, Arun, in terms of what the team has been driving on, and I probably won’t do service to the detail and the multiple factors that are driving here, the three buckets we see really are the stage architecture, which is our phrase for the combination of cluster design, cluster spacing and then, of course, the sand and water loading that we are feeding in through those clusters.

And the whole point of that stage architecture engineering is to get a more conductive fracture network more consistently placed along the entire lateral. And of course, that becomes more important as we drill longer laterals in these plays and drive efficiencies that way. So that’s the first bucket. The second bucket is kind of what we call chemistry, and that’s using the chemistry of the frac fluid try and enhance the permeability of oil in that fracture network. And so then, as a consequence, get more recovery from the poor system in place. And then the final bucket is really got a few things in it, but really, it’s this idea of real-time frac monitoring. And the approach here is traditionally in our industry 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.

And then sometime down the road, there would be a look back on and potentially optimization occur in subsequent wells. And what we are trying to — the network we are trying to crack with technology and telemetry is to be able to do that real time. And the learning from the signals we are getting back subsurface well we are pumping and then tune our frac design as we go and as a consequence, just be more efficient with that frac design, but also get more recovery along that long lateral. So really, those are the three buckets I’d speak to, Arun.

Arun Jayaram: It sounds like a nice endorsement of how a smart fleet technology, Jeff Miller. My follow-up, Brendan, is have you tested this kind of completion design outside of the core. And could there be any implications of, call it, Tier 2 locations on the map where you could boost the overall productivity to perhaps mimic Tier 1 type of economics?

Brendan McCracken: Yes. And we — 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 the math of where those 44 wells are across our land base. And what you can see from that is there’s spread across the land base. So what that is telling us is this — these completion designs are working across the Permian for us. And so as far as sort of the Tier 1, Tier 2 implications, really, what we are seeing is it’s making the Tier 1 stuff better. And the good news story for our acreage position is we are pretty much in the core of the basin across the board. So we’ve really been just using it on the acres we’ve got, which are really all in that Tier 1 bucket.

So — but I think your point is valid, which is moving locations from near premium into that premium bucket is a win, and we look to do that all the time as well. One of the things we’ve talked about on the new acres is that 800 premium count underwrites 3 bench development across the acreage. And Greg pointed out, we’ve got quite a number of wells in progress that we will be bringing on stream and those cubes are all either 3 or 4 bench cubes or even higher in some instances. So excited to see how those completion designs show up when we start to get them later this year.

Arun Jayaram: Great. Thanks. [Indiscernible].

Brendan McCracken: Thanks, Arun.

Operator: Your next question will come from Neal Dingmann at Truist Securities. Please go ahead.

Neal Dingmann: Good morning. 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. And I’m just wondering, would you kind of consider this kind of a maintenance plan? And if so, could you maybe speak to the — around the level of CapEx needed to sustain this?

Brendan McCracken: Yes, Neal, I appreciate it. Yes, we reiterated that 2024 view here today and 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 big movers are going to 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. So the implied midpoint of capital for ’24 and then settling in at that 200,000 barrels a day in the second half, make total sense. 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.

And we’ve talked about really 3 gates of decision making to consider around capital allocation for either maintenance or modest growth. And 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. And so that’s the first test. And then the second test would be does the world need more barrels and more BTUs. And then the third test would be what’s the execution risk on adding that activity. And if I just quickly run through that model here, today the buyback still screen more favorably than adding rigs and spreads to the program. And then our judgment today is the world isn’t asking for more barrels and BTUs from our company.

And then the third gate there, certainly, that execution risk from a year-over-year perspective feels a lot better than it did last year when inflation was running pretty hard. So — but still, those other 2 gates would have us staying in that maintenance mode.

Neal Dingmann: Yes. Agree. All that makes sense. That’s certainly to me as well. And my second question maybe for Greg, on the Permian. Specifically, can you address future potential maybe frac hits or needed well shut-ins. It seems to me kind of the plan you guys have talked about even now post deal, that you all have much more minimum level of shut-ins unlike a number of your various peers that are experiencing this.

Gregory Givens: Yes, Neil, thanks for the question. And you’re exactly right. That was one of 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. And what we’ve already seen, as I 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 were out there pumping today, why not knocking these newer wells off. And we’ll continue to optimize this as we go-forward, but we do feel like that is a big part of the value we are going to be able to bring to this acreage by not having that be a problem.

And some of these new completion designs also seem to be helping on that front as well.

Neal Dingmann: No. Great to hear. Thanks, Greg. Thanks, Brendan.

Brendan McCracken: Thanks, Neal.

Operator: Your next question will come from Gabe Daoud at TD Cowen. Please go ahead.

Gabriel Daoud: Hey, thanks. Good 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 as our performance on — or 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. And 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 & conde combined. So just curious if that’s more or less where you’re at today.

Gregory Givens: Yes. So as far as the forecasting goes, as I mentioned, a lot of activity going on in the play today. We are very pleased with what we saw in the first half and those wells continue to hold up. But we are going to be bringing on a lot more wells in the back half of the year. We are going to want to see how that productivity holds up in keeping in mind a number of the wells, over half the wells we are bringing online in the third quarter are going to be wells that — while we are influencing the tail end of the completion, we were not involved in those wells from their inception to bringing them online. So we do believe there’s a little uncertainty there. We want to see how those wells do. We’re quickly incorporating all of our completion techniques into our operations.

So you’re going to see, as we go through the third and into the fourth quarter, a whole lot of data coming in, and we are trying to be thoughtful about how we approach this. By later this year, we should have a much better sense of how well this uplift, not only is impacting our existing legacy portfolio, but the new wells and then how long it’s not just the number of wells that we need to see is the duration, how long this production uplift holds up. So we are looking forward to seeing that. And then as we continue to see that more consistently, we will start baking that into our forecast.

Brendan McCracken: Yes, Gabe, I think you had a question on the pro forma there, too. So yes, as Greg picked up earlier, we got about 60 to 70 Permian wells to bring on in the quarter. So it’s a fairly dynamic number, any given day here. But you’re right, we are running just a little over that 120,000 barrel a day at the moment.

Gabriel Daoud: Got it. Got it. Okay. Cool. Thanks, guys. That’s helpful. And then 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 ’24. But curious, I guess, what’s embedded in that $2.1 billion. Is it, I guess, 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 curious if you could maybe talk a little bit more about what we need to see for that $2.1 billion number. Thanks, guys.

Brendan McCracken: Yes, Gabe, I 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 again, what we’ve — we are telling the market here is that midpoint of the range feels like the right steering point with what we know. And we will just have to see where service prices trend. We’ve seen rig counts come off on both the gas and the oil side by about 15% from the peaks. And — if that continues, then that will keep driving further deflation and that could push us lower in the range. And we will just have to see, obviously, oil has ticked up a little bit, and gas has maybe been a bit stronger through the summer months. So we will see what that translates through to activities by the rest of industry. We’ve been clear about we are not adding activity, but we will see what happens across the rest of industry and tune our ’24 guide as we get closer to it.

Gabriel Daoud: Thanks, guys.

Brendan McCracken: Yes, thank you.

Operator: Your next question will come from Josh Silverstein at UBS. Please go ahead.

Joshua Silverstein: Yes. Thanks. Good morning, guys. Just thinking about the shareholder return profile versus the debt reduction you mentioned kind of up to 50% for the balance sheet portion of it. [Indiscernible] basically just 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?

Brendan McCracken: Yes. I think, Josh, there what we will do is we will follow the program here, which calls for the at least to incremental shareholder return over and above the base dividend. And then the rest will be available for that debt reduction, which is we are trying to take the debt down to 4. And so I think we will be very opportunistic to do that as we go along. And think we were thoughtful about the capital structure to enable that without extra cost. And so like you said, we’ve got some well-timed maturities in the next couple of years to be able to do that.

Joshua Silverstein: Got it. And then I mean you guys do have a [technical difficulty] now, it seems like you have a pretty good well performance there. I was curious on the rail infrastructure that you guys had mentioned. Is this supporting potential basin growth for you guys, an increased capital allocation? Or is it really just [technical difficulty]? Thanks.

Brendan McCracken: Yes. No, I appreciate it. Yes, we are excited about what we are seeing in the Uinta. And remember, the last 2 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. And so we made great progress on both those fronts. We are now railing to the Gulf, some 30% to 40% of our total into volumes. And with the 2 rigs running there, we are going to see a big production ramp in the Uinta through the back half of the year. So that rail infrastructure is low cost and scalable. And so that will afford us to be able to have higher Uinta production volumes through the back part of this year and into 2024, depending on how we set capital in ’24.

Joshua Silverstein: Got it. Thanks.

Brendan McCracken: Yes, great. Thanks, Josh.

Operator: Your next question will come from Doug Leggate at Bank of America. Please go ahead.

Unidentified Analyst: Good morning. This is John [indiscernible] on for Doug Leggate. Our questions really are on the Anadarko Basin. First of all, with the reduction of activity, what would you have to see in terms of prices to bring activity back there to that basin?

Brendan McCracken: Hey, John. Yes, good morning. On the Anadarko, really our team has done just an incredible job here. The focus on innovation has resulted in a substantial shallowing of our base decline 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. And the recent wells that the team had brought on stream in the first half of the year have been really strong performers. I mentioned earlier, we’ve been using the same completion design optimizations in the other assets as the Permian, and that’s the same here in the Anadarko. So we are encouraged by the underlying asset performance. And — but really with the gas and NGL fundamentals that we saw coming into the second half of the year is really why we chose to rotate capital out of there for the time being.

And so with the stronger gas and NGL fundamental into ’24, particularly later in ’24 once we see the start up of some incremental LNG pull off the Gulf Coast, that could be the signal that brings capital back into the Anadarko brings the rigs back there. So I think we’ll just watch for it. I’m not sure there’s a specific price toggle one way or the other because it’s always going to depend a little bit on cost structure as well. And the team has been really working hard on initiatives to reduce D&C costs and increased cycle times in the Anadarko as well. So I think it’s a little bit of a combination of those things, but for the big things we want to see a more healthy supply and demand balance on the gas side and the NGL side.

Unidentified Analyst: That’s very helpful. And just as a quick follow-up on the Anadarko. Just given the improvements in the underlying declines and productivity that you’re seeing. How long do you think you can actually do that for in terms of holding? How many years of inventory, how long do you think you can actually hold that flat potentially if you wanted to?

Brendan McCracken: Yes. So the Anadarko, the fantastic piece there is we’ve got a deep, high-quality inventory in that play as well. And really, we see over a decade of drilling inventory to hold that asset flat should we choose to allocate the capital there to do that.

Unidentified Analyst: All right. Thank you very much.

Brendan McCracken: Thanks, John.

Operator: Your next question will come from Umang Choudhary at Goldman Sachs. Please go ahead.

Umang Choudhary: My questions. I appreciate all the color on the strong performance in the Permian and the Montney. And I understand that there’s less clarity in terms of how the 3Q 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 pare the improved performance, which you’ve seen recently in your legacy assets and the implication to your production guidance next year.

Brendan McCracken: Yes, I appreciate it. Yes, cadence wise, a lot going on in the Permian here in the back half of the year. So we are going to see between 60 and 70 TILs in the third quarter. and just a little bit less than that in the fourth quarter, but rate up there as well. So that’s the setup through the back half of the year on cadence, which is going to see us at a total company level, averaged 210,000 barrels a day of crude and conde in the back half of the year, and then some of that will spill into early ’24 and then we’d expect to level back out at that 200,000 barrels a day by midyear and hold that flat through the back half. So that’s the cadence set up there.

Umang Choudhary: Got you. That’s really helpful. And 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?

Brendan McCracken: Yes. I appreciate the question there. So on hedging, really what we’ve done here is continue to use our next 12-month approach. So building the book out one quarter at a time over the next 12 months. And we’ve also continued to use three way structures to provide a soft floor that we are comfortable with, but also give some upside to higher price exposure, which, of course, would enable us to participate in a structurally stronger market. So in the second quarter here, we did add some second quarter ’24 hedges on the gas side. And so over that next 12-month period, we are about half hedged on oil and about 40% hedged on gas, again, primarily in those three wave structures. And I’m sure you saw it, but Slide 20 has got the details of that, but 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 quarter to a third of production level.

Umang Choudhary: Got it. Thank you so much.

Brendan McCracken: Thank you.

Operator: Your next question will come from Phillips Johnston at Capital One. Please go ahead.

Phillips Johnston: Thanks. In addition to the uplift in productivity that you’re seeing in this year’s vintage of wells in the legacy Midland [ph] properties. In the slide deck, you also mentioned older wells are outperforming forecast. Just wondering what kind of magnitude you might be talking about there, what you would trim that to? And which areas you’re seeing the biggest upside?

Brendan McCracken: Yes, Phil awesome pick up. Appreciate the catch on that. And Obviously, that’s one of the most efficient ways to add production is by optimizing base. And so 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 really inexpensive workover treatments that have been creating some boosts in our older vintage wells that we are excited about. So I don’t know, Greg, if you want to add anything there?

Gregory Givens: Yes. It’s really just a lot of great work by the teams, blocking and tackling, reducing failure frequency. But we do see a little improvement with some of the new frac designs we are pumping seem to have less impact on the parent wells. But really, just a lot of things that the teams are looking at that are adding up to a nice little beat there on the base side. And this is something we are focused on in all of the areas, not just the Permian.

Phillips Johnston: Okay. And I’m guessing that’s also not factored into your second half of the year production guidance or the ’24 guidance, correct?

Brendan McCracken: Well, I think what we’ve factored in here now is the performance uptick we’ve seen on the existing PDP. And so where the upside is still just what further decline abatement can we do, but we have included the PDP impacts that we are realizing today in the forward guide.

Phillips Johnston: Okay. Okay. That makes sense. And then just maybe an update on LNG Canada Phase 1. I realize you guys aren’t a direct participant, but it’s obviously going to help pricing in the [technical difficulty]. I think as of the Montney Day in September, I think the project was over 60% complete with timing in first quarter ’25. Just wondering how the progress has been since then?

Brendan McCracken: Yes. I will 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 percent complete here now. But 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 1 or pre-FID like several others. We do think it makes sense to have some exposure to LNG for our portfolio time. We think that’s complementary to our existing price diversification strategy in the Montney. Couple kind of ground rules, if you will. I think, one, we are not interested in an equity stake.

So I think we can take that off the board. But we’ve shown we can demonstrate great success by developing egress out of the Montney and into the rest of North America. And I think the logical extension of that is also to have a piece of global exposure here. And so our team is hard at work across each of those projects to find the right commercial solution for us. But I don’t know, Corey, if you’ve got any of those project update numbers of top of your head there.

Corey Code: Yes, sure, Brendan. So Shell talked about this a little bit yesterday, but I think they’re 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. So obviously, that’s coming soon and good updates from that standpoint.

Phillips Johnston: Okay. That sounds good. Thanks.

Brendan McCracken: Thanks, Phillips.

Operator: Your next question comes from Jeoffrey Lambujon at TPH & Co. Please go ahead.

Jeoffrey Lambujon: Good morning, everyone and thanks for taking my questions. My first one is 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 particular prove conservative for 2024 with maybe the same CapEx range you’ve been talking about actually able to generate more production than what’s modeled today. How should we think about the overall outlook potentially changing. So I just want to get a sense for if we should think about reductions to that spending range, maybe with less capital, again, needed to still achieve greater than the 200 level on [indiscernible] you’ve spoken to or if it might be more like a steady range on CapEx, but with the potential for volumes sold closer to what we might see in Q4 here for a bit longer?

Brendan McCracken: Yes, Jeoff, appreciate the question, and I love your take on it. I think what we’ll do, as we set ’24 is we’ll run those three gates on where does it make sense from a cash flow per share impact, what’s the world asking for in terms of barrels and BTUs. And then what do we see as the execution risk? And sitting here today, I think that maintenance level continues to feel like the right answer to those. But obviously, we’ll get a chance to look at that through the back half of the year. But that will be our starting point on that decision. And then the other piece that we’ll factor into it is just the level loading. We’ve worked really hard to create a level loaded program this year. We think that’s benefiting our teams greatly.

And so we want to be preserving that as we kind of go-forward into 2024 and setting up for a consistent level loaded program across the assets full year ’24. So those will be the things that we weigh as we work our way through this, and then we’ll be looking to optimize the returns, both return on invested capital and the return of cash to shareholders.

Jeoffrey Lambujon: Okay, great. And then my second one is just a follow-up on the Uinta, just given we’re about to see some additional contribution from that asset here in the second half, as you alluded to. I wanted to just ask simply what you need to see to allocate more capital there. I know you’ve been talking about the productivity comparisons. You spoke to the infrastructure earlier, kind of making room for that, if that’s ultimately where you decide to go. And I think you’ve spoken to some depth on 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?

Brendan McCracken: Yes, you bet. And so right now, the program we’ve got through the rest of ’23 here is absolutely return competitive with the rest of our portfolio. It sits right there on the on the same level of returns that we are seeing in the other assets. So that’s important, first of all, because otherwise, we wouldn’t put capital there. And then as far as trajectory from here, I think 2 rigs is going to really see a big ramp in volumes there. So that feels like the right level to be thinking about as we head into 2024, and we will just kind of watch and see the performance as we go through the year.

Jeoffrey Lambujon: Perfect. That’s all.

Brendan McCracken: Yes. Thank you, Jeoff.

Operator: 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. We’ve one question left in the queue from Scott Gruber at Citigroup. Please go ahead, Mr. Gruber.

Scott Gruber: Yes. Thanks for squeezing me in. Just a couple of follow-up questions. What level of overall cost inflation would align with the midpoint of the ’24 guide just kind of ballpark.

Brendan McCracken: Yes. Hey, Scott. Yes, glad we got you there, I apologize for any confusion. Yes, so really, that midpoint of that guidance range would be sort of the deflation trajectory that we are seeing currently. So as we’ve kind of reviewed service pricing. Most recently, 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 other categories like rigs and spreads. And so it’s basically including what we see today. And like I said, we’ll have to watch and see how things unfold if more deflation materializes as we go through the back half of the year.

Scott Gruber: Okay. Any way to quantify that? Is it kind of a mid single-digit type number? Is it trending towards double-digit [indiscernible]?

Brendan McCracken: I think, yes, in — so the numbers we are seeing are low single digit. And the only thing I’d say about that, of course, is it depends on your starting point for what I’ve seen other E&P comment on different numbers and it always just has to be rooted in what you’re starting from. And we had a number of fairly favorable service pricing arrangements in ’24 here — in ’23 here. So what we are seeing is kind of low single digits relative to that.

Scott Gruber: Okay. I appreciate the color. Thanks.

Brendan McCracken: Yes. Thanks, Scott.

Operator: My apologies again. At this time, we’ve concluded the question-and-answer session, and I will turn the call back to Mr. Verhaest.

Jason Verhaest: Thanks, Michelle, and thank you, everyone, for joining us today. Our call is now complete.

Operator: 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.