Coterra Energy Inc. (NYSE:CTRA) Q2 2023 Earnings Call Transcript

Coterra Energy Inc. (NYSE:CTRA) Q2 2023 Earnings Call Transcript August 8, 2023

Operator: Thank you for standing by. At this time, I would like to welcome everyone to the Coterra Energy Second Quarter 2023 Earnings Call. [Operator Instructions]. Dan Guffey, Vice President, Finance, Planning and Analysis and Investor Relations, you may begin your conference.

Daniel Guffey: Thank you, Cheryl, and good morning, and thank you for joining Coterra Energy’s Second Quarter 2023 Earnings Conference Call. Today’s prepared remarks will include an overview from Tom Jorden, CEO and President; and Shane Young, Executive Vice President and CFO. Also on the call are Blake Sirgo, Senior Vice President of Operations; and Scott Schroeder. Following our prepared remarks, we will take your questions during our Q&A session. As a reminder, on today’s call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures were provided in our earnings release and updated investor presentation, both of which can be found on our website. With that, I’ll turn the call over to Tom.

Thomas Jorden: Thank you, Dan, and welcome to all of you who have joined our call this morning. We’re looking forward to discussing our second quarter results as well as our approach to the business and outlook for the years ahead. First, some remarks on our second quarter results. We had an excellent quarter driven by production beats on oil, natural gas and natural gas liquids. Volumes on all 3 commodities exceeded the high end of our guidance. Our production beat was primarily driven by well productivity that exceeded our expectations. This was true in the Marcellus, Anadarko and the Permian. This beat was driven by many factors, including optimization of completion design, spacing, landing zone selection and better-than-expected performance from a project of 3-mile laterals.

Our go-forward well productivity should closely approximate current trends in the coming years. We are highly confident in our sustainable asset performance. Excellent results are easy to describe, but tremendously hard to achieve. It takes dedication and teamwork between our operations, marketing, midstream and regulatory teams. It takes support from our corporate engineering group, our machine learning team, our IT team and our accounting team. Mostly, it takes the dedication and passion of our field staff, who put their shoulder to the wheel 24/7, 365 days a year with a commitment to excellence and safety. The Coterra team is operating as one, and it is a pleasure to be a member of such an outstanding team. Our vision for Coterra is one of consistent profitable growth through the cycles, a vision made possible by hard work and perseverance.

We expect our CapEx for the full year to fall within our previously announced annual cost guidance range. Costs continued to moderate slightly, but not as significantly as we had hoped. Slide 12 in our investor deck shows that although we look ahead to a 10% to 15% reduction in some big ticket items, we foresee a net 5% reduction in total well cost as we look ahead to 2024. Second, I’d like to make a few remarks regarding our approach to the business. With top-tier assets, a pristine balance sheet and few contractual service commitments, we have tremendous flexibility for 2024 and beyond. Now as ever, our mission is to generate consistent profitable growth. Having outstanding oil and natural gas assets with a low cost of supply, allows us the wherewithal to accomplish this.

It takes discipline and, at times, a dose of courage. We will not stop and start our program with short-term swings in commodity pricing. We have learned over time that chasing the strip up or down is a fool’s around. Our experience tells us that in a cyclic commodity business, the winners are those that can maintain disciplined consistency. Highly reactive behavior can badly backfire, especially in a world where project cycle times can be longer than short-term swings in commodity prices. We choose as-steady-as-she-goes approach to our program design and execution. We stress test all of our opportunities at draconian low commodity prices, so that we can deliver reasonable returns through the ups and downs of the cycles. We play to win. Finally, let me make a few remarks regarding our outlook for the years ahead.

Although we are currently working on our 2024 plans, we will not be making specific comments on them. Our plans will be built with some simple considerations. First, based on range-bound assumptions of future commodity pricing, we estimate what level of total capital expenditure is appropriate for Coterra. We continuously reexamine our inventory with the goal of selecting the very best returns. We stress test these opportunities to ensure that they can withstand down drafts and pricing as well as increase in costs. We insist on flexibility, so that we can pivot if macro commodity conditions change. In long-term planning, we think of total Coterra capital. And within that framework, capital will flow from basin to basin as conditions warrant.

We have a firm conviction that production is an outcome, not a primary driver. Consistent annual progress is our goal, and if smart project architecture leads to quarterly fluctuations, so be it. We’ll have some large projects in 2023 and beyond, driven by our goal of achieving the best returns over the long haul. We don’t get distracted by quarterly fluctuations as projects come online. Although we like production beats, our commitment is to invest for results that can withstand commodity swings. These principles are in our corporate DNA. As we look ahead into 2024, we have options and flexibility. For example, we can drop capital in to Marcellus by more than $200 million versus 2023 and still hold the region’s production flat over multiple years.

We have the option to redirect the capital or to simply invest at a slower cadence. We also retain the ability to restore activity if the gas macro were to significantly recover. Although we’re confident in our ability to deliver on our updated 3-year outlook as shown on Slide 5 of our investor deck, we have a wide range of options on total capital and allocation. The outstanding quality and durability of our assets, the flexibility of our capital allocation, our organizational capacity and our consistent execution are what differentiates Coterra. As always, we prefer to speak about results rather than promises. Before I turn the call over to Shane, I want to welcome him to Coterra. Shane will be a key player in our team for many years to come.

We are absolutely delighted that he has joined the team. He will make us better. Welcoming Shane is a bit bittersweet or it’s on the heels of Scott Schroeder’s decision to retire. Today will be Scott’s last quarterly conference call. Scott’s career is one for the record books. With Cabot, Scott was instrumental in building one of the finest companies in our sector and a defining success for the Shale era. Scott’s vision and wisdom were key to the formation of Coterra and he has become a trusted adviser and dear friend to us all. We will miss Scott and wish him a fruitful and satisfying retirement. He leaves with our deep gratitude. With that, I will turn the call over to Shane.

Shannon Young: Thank you, Tom. It is a pleasure to be on today’s call. This morning, I will discuss our second quarter 2023 results, provide details on our shareholder return program, and update our activity outlook and guidance for the third quarter and for the full year. During the second quarter, total production volumes averaged 665 MBoe per day. Natural gas volumes grew to 2.9 Bcf per day and oil averaged 95.8 Mbo per day, which is a new high watermark for Coterra. In fact, all 3 production streams came in well above the high end of guidance. Our operations teams in all 3 regions executed nicely, which drove BOE production up 5% sequentially. The strong performance was driven primarily by positive well productivity and improved operational efficiencies.

Turn-in lines during the quarter totaled 39 net wells, within our guidance of 36 to 45 wells. Production growth during the period was more than offset by commodity price declines, which were down 30% quarter-over-quarter on a BOE basis, driving net income and cash flow lower relative to the first quarter. Coterra reported net income of $209 million and discretionary cash flow of $705 million during the quarter. These results are inclusive of realized cash hedge gains of $84 million. Second quarter accrued capital expenditures totaled $537 million, within our guidance of $510 million to $570 million, and free cash flow was $113 million after cash capital expenditures, which totaled $592 million. Based on strip prices, cash flow and free cash flow are projected to increase during the back half of 2023, and the company expects greater than 55% of its 2023 revenue to come from oil and NGL sales.

Turning to return of capital. Yesterday, we announced a $0.20 per share base dividend for the second quarter. Our annual base dividend of $0.80 per share remains 1 of the highest yielding base dividends in the industry at nearly 3% based on recent trading levels. Management and the Board remain committed to responsibly increasing the base dividend on an annual cadence. During the second quarter, despite relatively lower commodity prices and cash flow, Coterra continued to execute its return program by repurchasing 2.4 million shares for $57 million at an average price of $23.55 per share. In total, we returned 184% of free cash flow during the quarter. The company’s large cash balance afforded us the luxury to return capital in excess of our quarterly free cash flow and continue to buy our shares countercyclically at attractive prices.

Based on results year-to-date, Coterra’s returned $628 million to shareholders or 94% of free cash flow via our base dividend and share repurchases. We are reiterating our annual commitment to return 50% plus of free cash flow to shareholders. When taking into account recent strip prices, buyback activity completed to date and our base dividend, we expect to return well in excess of 50% of 2023 free cash flow. Lastly, I’ll discuss refinements to our 2023 guidance and activity outlook. First on capital. We are reiterating some of the company’s 2023 accrued capital estimate of $2 billion to $2.2 billion. While we are currently trending 1% to 2% above the midpoint of our guidance range, we are seeing clear signs of future cost softening on big ticket items such as rigs, steel and frac crews.

Other cost categories, including labor and surface rentals have been more sticky and flat to modestly up. Based on leading-edge service costs, coupled with the timing of our contract repricing, our best estimate based on information we have today is that we will see a 2024 dollar per foot decrease of approximately 5% as compared to 2023. We retain a substantial amount of flexibility for our 2024 capital program in all 3 basins and plan on detailing our program early next year as per our customary annual guidance release. On to production guidance. We are increasing our full year oil guidance by 3% at the midpoint to 91 to 94 Mbo per day, driven primarily by strong well performance in both the Permian and Anadarko basins. We are increasing our natural gas and BOE guidance 2% at the midpoint on the back of solid well performance in the Marcellus.

For the third quarter, we estimate production will average 640 MBoe per day, natural gas to average 2.8 Bcf per day and oil to average 89.5 Mbo per day. The sequential production decline is solely related to timing and was previously forecasted internally. As implied by our full year guidance, we expect to see a return to growth in the fourth quarter. In our investor presentation, we reiterated our 3-year outlook, which assumes the company achieves a 3-year oil CAGR of 5%. BOE and natural gas CAGR of 0% to 5% and with capital and activity that is flat to down relative to 2023 levels. One update in our presentation was a change in our oil CAGR outlook. We now expect our 3-year CAGR to be greater than 5%. This change is primarily driven by the observed strong well performance in 2023 to date.

We have yet to finalize 2024 capital investment allocation by region and retain significant optionality. We will continue to allocate capital to its most productive use. Based on recent strip and our outlook, our 2023 discretionary cash flow guidance is $3.35 billion, down from $3.6 billion in May. The decrease in cash flow is driven primarily by lower natural gas and NGL realizations. The 2023 free cash flow is now estimated to be $1.24 billion, down from $1.58 billion, which is due to lower discretionary cash flow and higher projected cash CapEx, which includes the cash impact of forecasted changes in AP at year-end. Turning to a few business unit updates. The Marcellus delivered strong well performance during the quarter. Production increased 9% sequentially, driving total company natural gas volumes 2% above the high end of guidance.

As previously communicated, we recently dropped Marcellus activity to 2 rigs and 1 crew. If this level of activity holds in 2024 and 2025, Marcellus capital could decline by at least $200 million per year while holding production relatively flat. In the Anadarko, our last 2 projects, which both came online in the second half of 2022, continue to outperform. We are currently fracking the 7-well Evans development, which is expected to come online during the fourth quarter. We are running 1 rig in the region during the back half of the year, which will provide nice momentum heading into 2024. In the Permian, we are currently running 6 rigs and 3 frac crews, 1 of which will be utilized as a spot crew. Permian turn-in lines are trending to the high end of our annual guide, largely due to operational efficiencies, including improving drilling and frac feet per day.

The incremental wells are expected to come online late in the fourth quarter and contribute minimally to 2023 annual volumes. Lastly, I’ll touch on unit costs. Cash costs, including LOE, workover, transportation, production taxes and G&A totaled $8.27 per BOE during the second quarter, down for approximately $8.90 in the first quarter. This was well within our annual range of $7.30 to $9.40 per BOE. One note on deferred tax guidance. After utilizing the bulk of our NOLs in the high commodity price environment during 2022, we expect deferred taxes to range between 10% and 20% of income tax expense in 2023. In summary, despite commodity headwinds during the quarter, momentum for Coterra continues. This is supported by strong operational execution, which led to production beats for the quarter and the need to raise our annual production guidance range.

The company remains well positioned to meet or exceed our 2023 as well as our 2023 to 2025 targets. Finally, I would also like to congratulate Scott Schroeder for all his successes over his 28-year career at Cabot and Coterra. He has been instrumental to creating a bright future at Coterra that we enjoy today. I’d like to personally thank him for all his efforts and the support he has provided me over the past month. With that, I’ll turn the call back to the operator for Q&A.

Q&A Session

Operator: [Operator Instructions]. Your first question is from Nitin Kumar of Mizuho Securities.

Nitin Kumar: First of all, congratulations, Scott, on your retirement, and congrats Shane on the new role. I want to start by unpacking — sorry, congrats. I want to start by unpacking the guide for third quarter a little bit. In your prepared remarks, you emphasized that the beat in the second quarter came from improved productivity, but you’re looking for about 7% decline in oil. Could you just walk us through maybe the cadence of completions for the rest of the year? And just kind of what leads to this guide?

Thomas Jorden: Nitin, it’s completely project timing and when projects come on. We’re in the process of bringing online what we call our mid- [indiscernible], which is 23 wells. And so the timing of when those come on as we complete that row is strongly driving our production cadence. We’ve got a — the next project, our Red Hills asset in New Mexico that will come on over the third and fourth quarter. We also, in the second quarter, had a nice pleasant surprise with the overperformance of 3-mile project, 4 wells in Reeves County. It’s completely project timing, our productivity is surprising us significantly to the upside. And as Shane said in his remarks, this was part of our plan. This is not a surprise to us, nor is it a concern.

Nitin Kumar: Got it. I guess, as my follow-up, I want to touch a little bit about the cash return. We saw you against a tough commodity tape dip into the cash balance a bit and return. I think it was 185% of free cash flow. Could you talk a little bit about how do you see — you have, I think, $840 million at the end of the quarter. How do you balance between maintaining some cash, being countercyclical in your buybacks? And how you’re looking at it sort of longer term?

Shannon Young: Yes. Thank you. I’ll take that. Listen, when I say on the return of capital program, first of all, the company looks at it from a full year program cycle, and focusing on quarter-to-quarter certainly make decisions, but I think we try to keep a vision of the totality of it in mind. If you look back over time, we’ve maintained a cash balance over the last 6 quarters as high as almost $1.5 billion, as low as in the $600 million. So I think that’s a range the company is comfortable operating within. And from there, I think as we make individual decisions quarter-to-quarter, we’re going to look at what is the free cash flow, what is the outlook for the coming period, and what’s our internal look at the value of the shares that are trading in the marketplace.

Operator: Your next question is from Arun Jayaram of JPMorgan Chase.

Arun Jayaram: I wanted to get some more details on the slight change in your 3-year outlook. Now you’re highlighting the potential to drive annual oil growth above 5%, which was 5% below before that. What is driving that slight change? And does that contemplate the potential reinvestment of $200 million, call it, from the Marcellus to your 2 other oil plays?

Thomas Jorden: Yes, Arun, it’s well productivity is driving that change fairly and simply. And no, there’s no assumption of reallocation in that 3-year plan.

Arun Jayaram: Understood, Tom. And what would — as you and your team look at the 2024 outlook, just looking at strip pricing today, would you say that there’s a better than 50% chance that you do decide to reallocate that just given your inventory depth in the Delaware Basin?

Thomas Jorden: No, I would not say.

Arun Jayaram: Okay. All right, Tom. I just wanted to get your thoughts on that. But for now, it seems like that $200 million, you haven’t made a decision on it, fair enough?

Thomas Jorden: That’s correct. Thanks, Arun.

Operator: Your next question is from Umang Choudhary of Goldman Sachs.

Umang Choudhary: And also congratulations, Scott, for your retirement. We will miss you. And, Shane, congratulations, look forward to working with you. Let me start with the cost deflation point. I appreciate all the details, which you provide on Slide 12. You mentioned that some of your contracts are staggered, so you might not realize the full benefit in 2024. Can you remind us the percentage of your overall CapEx, which will be exposed to those cost savings? And then to be sure, this is not incorporated in your 3-year outlook?

Blake Sirgo: Yes, this is Blake. I’ll take that one. Really, what we’re trying to show on Slide 12 is how our cost structure is and is not moving throughout ’23. So when we built the budget, we had some strong indications that our leading cost indicators were coming down. And most of those have come to fruition. So you can see with our midyear repricings, we gained ground on rigs, OCTG, frac sand, but it’s really the remaining market piece of our cost structure that just hasn’t seen the same deflation. So that part has been pretty sticky. It’s a bunch of smaller services driven by really underpinned by labor and fuel, and we just haven’t seen that deflation there. So all we’re assuming when we do the 5% is that those leading-edge indicators on those services we’ve called out, maintains for a full year, whereas this year, we only got to realize them for half a year.

Umang Choudhary: Got you. That makes sense. And then I just wanted to go back to the 3-year outlook. I’m trying to understand your earlier comments about maintaining a consistent operational program and some of the recent efficiency gains, which you have realized. What does it mean for your activity plans? Would it mean that you will drill more wells, complete more wells, more productive wells? And how does that change your thoughts around long-term capital spending?

Thomas Jorden: Well, certainly, we’ll drill more productive wells. And with our operations team, we will achieve increasing operational efficiencies. We — as we’ve outlined in our deck, in the Permian, we have a 51-well project underway, and that’s remarkable and offers the opportunity for some great efficiencies. It’s going to be stunningly productive. I’ll say, as we look at all of our options, we look to see what’s our outlook for commodity prices, how low can the commodity price fall where we would still generate a really nice return on our capital. And there is always a bit of wanting to skate where the puck is going to be on commodity pricing. So — but we’re going to be disciplined. We’re not going to chase the strip, as I said, but we also like to be consistent.

I mean chasing the strip works both ways. It means racing to add activity when prices are high, but it also means panicking when prices are low and dropping activity, and that can be horribly destructive to everything we want to accomplish. It could be destructive to your well productivity, it can be destructive to operational efficiency, and you can exactly time it wrong. So consistency is a luxury that Coterra affords, and we intend to exercise it.

Operator: Your next question is from Doug Leggate of Bank of America.

Doug Leggate: Let me offer also my thanks and gratitude to Scott for all his help over the years. And Shane, I look forward to working with you. Gentlemen, I wonder if I could start with a little housekeeping point. It’s a little subtle observation, I just wonder if it’s something worth talking about. If we look at your Permian production mix going back last couple of years, it seems to us — I’ll just give you the numbers here. If I go back to late ’21, you were about 35%, 36% natural gas yield. End of last year, it was 34%, first quarter, it was 32%. This quarter, it’s 31%. Is there something going on there? Or is it just a function of flush oil production?

Thomas Jorden: We — if there’s some overprint of it, we’re not aware of. I think it’s — yes, it may be a function of some of our spacing and getting spacing right, so that we’re not seeing GOR increases rapidly on some of our developments. But overall, we see a fairly consistent analysis of our assets. Blake, do you want to comment on that?

Blake Sirgo: Yes. I’d just say, our program is driven by constantly high-grading. And so in the Permian, that means our oils projects come to the . So our team is doing a great job with that. I’m not surprised that it went on.

Doug Leggate: Okay. I just wondered if there was something different about what you guys are doing, but thank you for that. My follow-up is really a clarification question on the earlier comments about spending. Shane, you touched on the Marcellus and your activity level obviously dropped earlier this year. So understanding everything Tom said about accepting the growth as an output. It sounds like you’re signaling that for the current level of activity, you’re — your CapEx could reasonably be in the $ 1.9 billion, maybe even lower range. Am I reading that wrong? Or can you just elaborate a little bit on what you were trying to signal there?

Shannon Young: Yes. Look, I think what I was trying to say is we currently have 2 rigs running and 1 crew in the Marcellus. And if we were to maintain that level of activity into the future, that our annual capital would be $200 million lower in the Marcellus area. So I think that’s — that was sort of the message that we’re trying to deliver based on where activity is today.

Doug Leggate: And that holds you flat in the Marcellus?

Shannon Young: Battles production flat in the Marcellus.

Operator: Your next question is from Michael Scala of Stephens.

Michael Scialla: I’ll offer my congratulations to both Scott and Shane as well. Curious if any of your investors are telling you that they don’t want to see oil growth of more than 5% over the next few years. Tom, you mentioned the flexibility that you have, but you don’t want to be reactionary. What are your thoughts around potentially cutting CapEx and just holding production flat?

Thomas Jorden: Mike, we’ve got a wide range of investors, as you can imagine. We have different voices. Quite frankly, we have some investors that tell us that if anybody is earning the right to grow, it’s this team. We have other investors that are — feel differently. We always enjoy conversations with our investors in getting feedback, and we’ll certainly be doing that on the heels of this call. But I think the investors that I think resonate with our story are looking for consistency, and they’re not buying Coterra to just ride a wave up or down. They want to see some progress. And that’s what we’re here to do.

Michael Scialla: Makes sense. Tom, you mentioned that Culberson row 51-well project seems like an exceptionally large group of wells there. Can you give a bit more color on what are the potential savings, where do those come in, and maybe the timing of getting those wells online?

Thomas Jorden: Yes. I’ll start it out, and I’ll let Blake take it home. But this is exactly what our Shale era is needing. We can take advantage of infrastructure. We can take advantage of operational efficiencies. We can take advantage of certainly our electrification, and we can take advantage of minimizing any kind of parent-child interference. We can stage the wells coming online in the way that manage this reservoir. It’s just really everything that the last decade has led up to in terms of taking advantage of our own technical innovations. Blake, do you want to say anything?

Blake Sirgo: Yes, sure. I know the headline reads 51-well project, but I think it’s important to share how our ops teams look at it. What we’re really doing is taking 6 distinct drill spacing units and prosecuting them in 1 consistent row. So no big changes on well per section or completion design. This is all about concentrating activity to maximize efficiency. So all those things Tom said, we’re cutting down on mobs. We’re parking frac crews where they can get the most pump hours per day. We’re centralizing and co-mining facilities and infrastructure. When you bring all that together, all those efficiencies really add up. And so as we model this project, our dollar per foot is coming in about 8% lower than our current cohorts on average. So that’s just the power of all that. What our Permian team is really doing is executing efficiencies on a grand scale coming to bear.

Thomas Jorden: I’ll also add, we’ll be bringing those wells online as we go. It’s not a situation where we wait to bring 51 wells online when the last one is completed. We staged them online continuously as we’re continuing to drill and complete.

Operator: Your next question is from Neal Dingmann of Truist Securities.

Neal Dingmann: Scott, thanks for everything. It’s been great working with you. My question first is on OFS cost, specifically. Could you guys just talk maybe, we hear a lot about cost deflation, OTCG and all those things. But I’m just wondering, Tom, maybe more or less how you all think about spot versus long-term contracts? I know you’ve in the past had some opinions. How you think about the 2? And is there a big pricing difference between the 2 today?

Thomas Jorden: Well, it depends on the particular item you’re speaking of. We — and it also depends on what you mean by long-term contract. If we have a program that we know we’re going to execute even going out a year, what we’ll typically do is look at what portion of that we’re willing to lock in. So as you know, we really try to avoid long-term commitments because it limits our flexibility. But for example, we’ll look — if we have 6 rigs running in the Permian, we may look at a downside commodity case and say, okay, we know for sure that we will have 3 rigs running. So we may have 3 of them on a 1-year contract and 3 of them on month-to-month. And so we really try to balance the value of the commitment against the value of the flexibility. But, Blake, do you want to say anything about that?

Blake Sirgo: I think you nailed it. It’s all about the value proposition. Not a year ago, we were signing contracts to hopefully keep inflation from rising. Today, we’re looking at contracts where we can see deflation if we entered into longer-term deals. And so we just have to balance those things, because they can reduce our flexibility, and that’s what we are on the downside cases.

Neal Dingmann: No. Great color. And then if I could, just on the last one, maybe a little bit on what Michael was just asking you. Just on that 51-well pad, does seem like great opportunity. Anything you could say on just details around where that is and just how you’ll tackle that one?

Thomas Jorden: Well, it’s in Culberson County. It’s in sort of the South Central Culberson County on the Eastern side. We call it the [indiscernible] row named after landowners out there, but it’s in a great area. It’s well defined. We’ve got a lot of calibration, good reservoir, good pressure, good oil. I mean it’s ready to roll.

Operator: Your next question is from Derrick Whitfield of Stifel.

Derrick Whitfield: Congrats to both Scott and Shane as well. Tom, with regard to your Q2 production beat, you noted better-than-expected well performance in cycle times in your prepared remarks. Given the degree of your oil beat and the amount of times you’ve referenced well productivity in this call, could you speak to the new designs or landing zones tested more specifically, which contributed to better-than-expected well productivity?

Thomas Jorden: Well, I don’t want to get specific on that. I will say that in the Wolfcamp, there’s a mixture of sand and shale landing zones, and we’ve changed our thinking on how to best exploit those different landing zones. It’s a combination of where we land our wells, how we space our wells, but also how we complete those wells? We’ve learned to do a little different completion, whether we’re in a sand or shale. I think that we also have a perhaps slightly different viewpoint than some of our competitors on the impact of what, it’s called cube drilling or some people call it tank drilling, and how to manage that. But really, it’s a sum of a lot of innovations over time. And I also want to credit our machine learning team.

I know you — a call doesn’t go by or I don’t say something about machine learning, but it’s really been transformative and become a very, very trusted partner with our operations teams and project planning. And it’s changed our thinking on some of the ways these parameters interact. Blake?

Blake Sirgo: Yes. I would — well spacing and frac design are a never-ending topic at Coterra. We debate them constantly, and we’re — we don’t ever settle that the current design is the best. So you’re seeing that across the portfolio this year.

Derrick Whitfield: And for my follow-up, regarding the 4 landing zones that you were referencing, Tom, just earlier in the Bone Spring, does your testing there this year have the potential to impact the relative allocation of capital in the Permian over the next 3 years if results are as you guys expect?

Thomas Jorden: I don’t think it will impact the relative allocation. We have a lot of projects lined up that it will impact. I mean as we look out the next 3 years, I don’t — I think it will help us to optimize based on what we learn. We’re continuously trying to optimize, but I don’t think it would necessarily change our capital allocation.

Operator: Your next question is from Roger Read of Wells Fargo.

Roger Read: Going to come back and hit some of the same, let’s call it, capital efficiency, productivity questions that have been asked. But if you step back and look across, and you do have different collection of assets in some of the other companies in terms of being a pure play, you’re looking at your productivity and efficiency, not so much where the gains have been, but where do you see the greatest opportunity going forward? Should we be focused on the Permian? Or is it continuing to be the Marcellus here?

Thomas Jorden: I think all 3 are right for increasing productivity. We’re very pleased with our Anadarko Basin flowback. It’s, again, surprising to the upside. Our Marcellus team has done a really, really nice job on a number of fronts. One is just optimizing our delineation, our slide deck updates, some numbers on our Upper Marcellus viewpoint, and we’re seeing some encouraging results there. They’re also doing a really nice job of just some operational improvements in field. There’re a lot of challenges in the Marcellus that are unique to the Marcellus. And a lot of challenges are unique. I would say our operating teams across our platform are learning from one another and a lot of that operational optimization, but we really see opportunity everywhere we look. Blake, do you want to add to that?

Blake Sirgo: Yes. Just saying the Marcellus, our team has done a fantastic job focusing on lateral length. Over 50% of our program this year exceeds 10,000 feet. We actually have a couple of wells with total measured depth in excess of 25,000 feet. So pretty light sale performance that’s really helping drive down our cost per foot. In the Permian, it’s all about these wells per project, these bigger developments that take advantage of project size. Our average wells per project is up about 23% just over the last 2 years. We expect that to continue.

Roger Read: Okay. So fair to say scale is a big contributor in the Permian — scale of any individual development or pad?

Blake Sirgo: Right. Our drilling and completion fee per day are up also. I mean our crews are hitting records on pumping hours per month. Our drilling fee per day is up 14% this year. But that’s what we expect. That’s what we do every year.

Roger Read: Okay. I appreciate that. And then follow-up question. I’m going to apologize for asking 2 parts within 1 question, but they go together, so role with me, if you would. The CapEx, looks like it’s going to be above the midpoint for ’23. It sounds like everything is pointing to lower in ’24. I was just hoping you could give us a little — a nugget here or there as to why we should have confidence that a potential outspend, even if only marginal in ’23, doesn’t carry through to ’24?

Blake Sirgo: Yes. I think that’s why we gave Slide 12 to kind of give some color on deflation. When we built the budget, we were taking all the best information we had at the time and if that deflation had rolled through the entire cost structure, we feel very confident we’d be at the low end of the range, but it just hasn’t materialized. We’re seeing it on a few leading items, but not through the whole cost structure. So when we give the 5% going into ’24, all that assumes is the gains we’ve got so far this year continue with nothing else.

Roger Read: Okay. And then could I ask one follow-up on the current deflation. What percentage is related to logistics or diesel costs or anything like that? Just noting that oil has gone back up to the mid-80s and fuel prices have followed to some extent.

Blake Sirgo: Yes. I don’t have that exact call out. I can tell you, it’s not pretty much baked in dollar services.

Operator: Your next question is from Kevin MacCurdy of Pickering Energy Partners.

Kevin MacCurdy: A question about the trajectory of OpEx this year. The first 2 quarters were at the higher end of guidance, and you didn’t change your full year guidance. So that suggests the second half of the year would need to be at the lower end of the range. Kind of what are you seeing out there that gives you comfort on the second half OpEx, especially given the lower volumes outlook?

Blake Sirgo: Well, I’d say our LOE is down quarter-over-quarter. So that’s the big one. We expect that to continue throughout the year. We’ve seen a little pressure in GP&T that’s not unexpected. Most of our portfolio has CPIs that are capped, but we’re hitting those caps this year. But we’ve modeled that out. And as you can see in our full cost, we’re front loaded and expect to come in, in the middle of the range.

Shannon Young: Yes. I would say sort of on cash costs sort of as we highlighted for the quarter. In addition to LOE overall, we’re down from $8.90 a BOE last quarter down to $8.27 BOE this quarter. So I think we feel like we’re trending in the right area.

Kevin MacCurdy: Okay. And digging into the production guide a little bit. You mentioned that the 3-mile laterals were outperforming your expectations, and that you’re seeing some improvement in cycle times. Just kind of curious how do you risk those 2 items when calculating your third quarter and fourth quarter guidance?

Thomas Jorden: Well, based on our experience with long laterals. I mean, long lateral performance is something that we’re all still learning. As we went from 1-mile to 2-mile horizontal wells, we had to learn what the uplift from 1 to 2 is. It’s depending on the reservoir, depending on the spacing, depending on the nature of the flow back. And although we have some experience with 3-mile laterals, we don’t have broad experience in any 1 area. We’ve got a 3-mile project in several different areas, this one was in Reeves County, where the operating environment is so different. And just quite frankly, the well surprised the upside. I mean I wish I had some grand conclusion, but it just — they flowed back a little stronger and with a little more uplift over a 2-mile than we had forecasted.

Operator: Your next question is from Leo Mariani of ROTH MKM.

Leo Mariani: I just wanted to stick with some of the line of questioning here on well productivity. You mean I think that the one that kind of stood out to me was the Marcellus in the second quarter. So material increase on the production 9%. Typically, I guess, I kind of think of the Marcellus as being sort of an older, more mature play, where there’s probably not a tremendous amount of sort of tweaks and improvements that can sort of be had here. But it certainly looks like maybe that wasn’t the case here in the second quarter. And it didn’t seem like there were some outsized number of wells that came online, just seems like some outsized production growth. So can you maybe give us a little bit more color around why the Marcellus was particularly strong in the second quarter?

Thomas Jorden: Well, I would say that our team is really hitting their stride. We have a fantastic operational team, both in the office and in the field when it comes to the Marcellus. The team has done a lot to manage and understand parent-child effects and really tailored our completions around that, tailor our well spacing. And they’ve really done a great job in revising our forecast methodology. And we’re forecasting much more accurately. And just really a big shout out to them across the board. They’ve got some great projects staged both this year and as we look ahead. And it’s a mixture of Lower and Upper Marcellus, and they’ve just made tremendous strides in understanding spacing, understanding completion design, understanding how to manage well-to-well interference and flowing back prudently. I mean it’s just — it’s almost everything coming together at once. They’re doing a tremendous job.

Leo Mariani: Okay. That’s helpful. And just kind of turning to CapEx. You guys said you’re probably going to end up being a couple of percent over the midpoint here in ’23. As I kind of looked at the sort of accrual numbers, and maybe you’re looking at the cash numbers as you’re kind of getting to that, so maybe you could kind of let us know if that’s kind of accrual versus cash. But I think in either case, it implies a pretty healthy downturn in fourth quarter CapEx, something maybe closer to the low 500s. So I just want to make sure I’m reading that right on the capital into 4Q. And are you guys kind of looking at sort of accrual or cash when you’re talking about kind of where you think you’re going to end up here in ’23?

Shannon Young: Leo, Shane here. Yes, as it relates to 2023, and the guidance range for the accrual is $2 billion to $2.2 billion. And what we said is we think we’re trending presently that 1% to 2% sort of above the midpoint within that range. So that’s really in reference to the accrual number that’s out there relative to the cash number. Obviously, the cash number is going to be impacted by timing around AP between the beginning of the period to the end of the period. As it relates to your observation on the fourth quarter, look, you’re absolutely right, maybe even a little lower than the numbers you were referencing at the midpoint when you look at it, and we feel good about that. We’re letting go of some spot crews sort of as we get through the end of this quarter in both the Permian and the Anadarko, and that’s what’s really leading to the lower activity that leads to lower accrued CapEx.

Operator: Your next question is from Paul Cheng of Scotiabank.

Paul Cheng: Tom, you mentioned that you benefit from the 3 miles well in the second quarter. Could you give us an idea then how many of the 3-mile wells that you’re going to drill for the next, say, 2- or 3-year program? And also in your Permian overall portfolio, what percent of your well could have the opportunity to be 3 miles? That’s the first question. The second question is talking about the larger pad, not just on pad that you expect to increase further. How you maybe manage between the better economy of scale with the larger pads, but also that maybe reducing visibility of the instant learning curve going back into the completion design and everything, given that it’s larger pad size?

Thomas Jorden: Thank you for those questions. We don’t have a tally of our 3-mile inventory. I will say it’s going to be a small part of our program generally. A lot of our lands are already developed or parsed out for 2-mile wells. And so 3 miles are going to be the exception. Go forward, I think you might see a project or 2. Marcellus probably will have the most 3-mile wells of our program just because that Upper Marcellus is wide open, and we’ll be taking advantage of that fully. But Permian is going to be a rare instance. And then as far as your question on the larger project size and the loss of the ability to cycle learnings, if I understand your question properly, that’s — that is a 2-edge sword. It also will give us the opportunity to test a lot of things, because with a 51-well program you have a lot of opportunity for control and test.

One of the things that is [indiscernible] in our space is if you have an individual small project and you march off and change some parameters, you don’t always have that control experiment to compare it to. So the 51-well project will have the opportunity to have several subtests within that to have good offset control and really normalize out some of the geologic and other attributes that can cloud your conclusions. So it’s a good question. We think that we’re ready for a project of this size, and we do really look forward to delivering outstanding results with it.

Operator: Your next question is from Noel Parks of Tuohy Brothers.

Noel Parks: I wondered if you could talk a bit about your thoughts on sort of the risk reward of infrastructure investment going forward from here? And I’m thinking in particular about this low we’re in with gas prices, oil strengthening and that makes me think, of course, about the Permian and associated gas. And I thought there’s somewhat mixed signals about how that might fare with the LNG uplift on the horizon. And so just between Marcellus addition and of course being in the Permian, just your thoughts on maybe what infrastructure priorities might look like heading into LNG?

Blake Sirgo: Yes. This is Blake. I’ll take that one. Your first question around Waha. Waha has traditionally been pressured, but we’ve actually seen it open up quite a bit this year. That’s with the new expansions coming online. Some of the forecast revisions coming out of the Permian, Waha is looking stronger. And there’s plenty of good options there for — to get Permian gas to LNG. We look at every single one of them. We just haven’t found 1 that works for us yet. Up in the Marcellus, we do have room to grow if we chose to. We know the pipes we can move the gas on. It might come with a little higher cost than we’re seeing now, but that’s factored into our economics.

Noel Parks: Okay. Okay. Fair enough. And I wonder, as far as what you’re seeing in terms of some cost softening on the horizon, just wondering, are you seeing significant divergence sort of in vendor behavior from basin to basin? Are any of your basins are vendors looking sort of more anxious and more proactive about sort of working on price with you? Or is it fairly uniform?

Blake Sirgo: Yes. This is Blake. I think it’s fairly uniform. I mean there’s always nuances between basins, but rigs and crews have wheels. And if the arbitrage is big enough, they’ll go to another basin. But, in general, we have great service partners we’ve been with a long time, and we work together through ups and downs.

Operator: There are no further questions at this time. I will now turn the call over to Tom Jorden for closing remarks.

Thomas Jorden: Well, thank you, everyone, and I’d like to turn the call over to Scott for some closing remarks.

Scott Schroeder : Thank you, Tom. And thank you, everyone. It’s been a tremendous ride. I’m extremely proud of what we put together here. Coterra is a great company and all of you and all the investors are in great hands. It’s a unique organization. It was something that people didn’t see coming, but I think 2 years into this, everybody is very happy internally, and I hope externally that it all came together. I’ve been tremendously blessed, and I thank all of you for your support and trust over the years and rest assured that you’re in great hands with Shane and the entire Coterra team as you go forward. Again, thank you for everything.

Operator: This concludes today’s conference call. Thank you for your participation. You may now disconnect.