Thank you for your patience. I would like to welcome everyone to the Coterra Energy Second Quarter 2023 Earnings Call. Dan Guffey, Vice President of Finance, Planning and Analysis and Investor Relations, please proceed with your presentation.

Thank you, Cheryl, and good morning. 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.

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 three 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 three-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 errand. 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 a 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 downdrafts and pricing as well as increases 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 into the 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 are confident in our ability to deliver on our updated three-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 differentiate 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.

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 three production streams came in well above the high end of guidance. Our operations teams in all three 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 one 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 three 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 three-year outlook, which assumes the company achieves a three-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 three-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 two 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 from 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 in 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.

Your first question is from Nitin Kumar of Mizuho Securities.

First of all, congratulations to Scott on your retirement, and congratulations to Shane on the new role. I want to start by discussing the guidance for the third quarter a bit. In your prepared remarks, you mentioned that the improvement in the second quarter was due to enhanced productivity, but you are expecting about a 7% decline in oil. Could you walk us through the timeline of completions for the remainder of the year and what factors contribute to this guidance?

Nitin, the timing of our projects is key. We are currently working on bringing our mid-independents online, which consists of 23 wells. The completion schedule for these wells significantly influences our production rate. Our upcoming project, the Red Hills asset in New Mexico, is expected to start production in the third and fourth quarters. Additionally, in the second quarter, we were pleasantly surprised by the strong performance of a three-mile project involving four wells in Reeves County. The timing of the projects is critical; our productivity has exceeded expectations. As Shane mentioned earlier, this aligns with our plans and is neither a surprise nor a concern for us.

Got it. For my follow-up, I want to discuss the cash return. We noticed that despite a challenging commodity environment, you dipped into the cash balance a bit and returned about 185% of free cash flow. Could you explain how you view your cash position, which I believe was $840 million at the end of the quarter? How do you manage the balance between maintaining some cash, being countercyclical with your buybacks, and your long-term perspective on this?

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 makes 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 six quarters as high as almost $1.5 billion and 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.

Your next question is from Arun Jayaram of JPMorgan Chase.

I wanted to get some more details on the slight change in your three-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 two other oil plays?

Yes, Arun, it's well productivity that's driving that change fairly and simply. And no, there's no assumption of reallocation in that three-year plan.

Understood, Tom. As you and your team assess the 2024 outlook and considering current strip pricing, do you believe there is a greater than 50% likelihood that you will choose to reallocate that due to your inventory levels in the Delaware Basin?

No, I would not say.

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?

Your next question is from Umang Choudhary of Goldman Sachs.

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 three-year outlook?

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 maintain for a full year, whereas this year, we only got to realize them for half a year.

Got you. That makes sense. And then I just wanted to go back to the three-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?

We will certainly be drilling more productive wells and, with our operations team, will increase our operational efficiencies. In the Permian, we have a 51-well project in progress, which is impressive and presents an opportunity for significant efficiencies. It is set to be highly productive. As we evaluate various options, we consider our outlook on commodity prices, exploring how low prices can go while still allowing us to generate strong returns on our capital. It’s important to anticipate where commodity pricing is headed. We will stay disciplined; we are not going to chase prices, but we aim to maintain consistency. Chasing prices can lead to issues on both ends—rushing to increase activity when prices are high and then scaling back when prices drop, which can be detrimental to our goals. It can negatively affect well productivity and operational efficiency, and timing it wrong can lead to mistakes. Thus, consistency is a valuable strategy for us at Coterra, and we plan to uphold it.

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

Let me express my thanks and appreciation to Scott for all his support over the years. Shane, I look forward to collaborating with you. I'd like to start with a minor housekeeping item. It's a subtle observation, but I wonder if it's worth discussing. If we examine your Permian production mix over the past few years, we notice that if we go back to late 2021, your natural gas yield was around 35% to 36%. By the end of last year, it had decreased to 34%, then it was 32% in the first quarter, and now it stands at 31%. Is there a specific reason for this trend, or is it simply a result of flush oil production?

If there’s any overprint of it, we are not aware. It may be related to our spacing and ensuring it's correct so that we do not see increases in GOR too quickly on some of our developments. Overall, we observe a fairly consistent analysis of our assets. Blake, do you want to add anything?

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 forefront. So our team is doing a great job with that. I'm not surprised that it went down.

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, 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?

Yes. I was trying to convey that we currently have two rigs and one crew operating in the Marcellus. If we maintain this activity level going forward, our annual capital expenditures in the Marcellus could be $200 million lower. That was the essence of the message regarding our current activity.

Your next question is from Michael Scala of Stephens.

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?

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 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 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.

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?

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 manages 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?

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.

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 stage them online continuously as we're continuing to drill and complete.

Your next question is from Neal Dingmann of Truist Securities.

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 two? And is there a big pricing difference between the two today?

Well, it depends on the specific item you're referring to, and also on what you consider a long-term contract. If we have a program that we know we’re going to execute even a year out, we typically assess what portion of that we’re comfortable locking in. As you know, we prefer to minimize long-term commitments to maintain our flexibility. For instance, if we have six rigs operating in the Permian, we might evaluate a downside scenario for commodities and determine that we can confidently run three rigs. Therefore, we might put three of them on a one-year contract while keeping the other three on a month-to-month basis. We aim to strike a balance between the benefits of commitment and the advantages of flexibility. Blake, would you like to add anything?

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.

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?

It's located in Culberson County, specifically in the south-central part on the eastern side. We refer to it by the name of the local landowners. The area is excellent with clear definitions, ample calibration, a good reservoir, solid pressure, and high-quality oil. It's fully prepared for operations.

Your next question is from Derrick Whitfield of Stifel.

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?

I don’t want to go into specifics, but in the Wolfcamp, we have a mix of sand and shale landing zones, and our approach to exploiting these zones has evolved. It involves not only where we place our wells and the spacing between them but also how we complete those wells. We have adapted our completion techniques depending on whether we are in sand or shale. Additionally, we may have a different perspective than some of our competitors regarding the impact of cube drilling, also known as tank drilling, and how to effectively manage it. Ultimately, it’s a combination of various innovations we've implemented over time. I’d also like to acknowledge our machine learning team, which has become an invaluable asset to our operations and project planning, significantly altering our understanding of how these parameters interact. Blake?

Yes, well spacing and frac design are an ongoing discussion at Coterra. We continually evaluate them and never conclude that our current design is the best. This is evident across the portfolio this year.

And for my follow-up, regarding the four 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 three years if results are as you guys expect?

I don't believe it will affect the relative allocation. We have many projects that it will influence. Looking ahead over the next three years, I think it will assist us in optimizing based on our findings. We are always working to enhance our processes, but I don’t foresee it altering our capital allocation significantly.

Your next question is from Roger Read of Wells Fargo.

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 a different collection of assets than 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?

I think all three 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 the field. There are 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?

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 two years. We expect that to continue.

It’s accurate to say that scale plays a significant role in the Permian, specifically regarding the size of any particular development or pad.

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.

Okay. I appreciate that. And then follow-up question. I'm going to apologize for asking two parts within one question, but they go together, so roll 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 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?

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.

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.

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

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

A question about the trajectory of OpEx this year. The first two 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 of OpEx, especially given the lower volumes outlook?

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.

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.

Okay. And digging into the production guide a little bit. You mentioned that the three-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 two items when calculating your third quarter and fourth quarter guidance?

Based on our experience with long laterals, we are still learning about their performance. When transitioning from one-mile to two-mile horizontal wells, we had to understand the uplift associated with that change, which varies depending on the reservoir, spacing, and flowback nature. Although we have some experience with three-mile laterals, we lack extensive experience in any specific area. We have a three-mile project in various locations, including Reeves County, which presents a very different operating environment. The well performed better than we anticipated, and while I wish I could provide a definitive conclusion, it showed stronger flowback and uplift compared to our forecasts for two-mile laterals.

Your next question is from Leo Mariani of ROTH MKM.

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?

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 has tailored our completions and well spacing accordingly. They have also done a great job in refining our forecasting methodology, resulting in much more accurate forecasts. A big shout out to them across the board. They have some great projects lined up for this year and beyond, which include both Lower and Upper Marcellus. They have made tremendous progress in understanding spacing, completion design, and how to manage well-to-well interference and flowing back prudently. Everything seems to be coming together at once, and they are doing an outstanding job.

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?

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.

Your next question is from Paul Cheng of Scotiabank.

Tom, you mentioned that you benefit from the three miles well in the second quarter. Could you give us an idea then how many of the three-mile wells that you're going to drill for the next, say, two- or three-year program? And also in your Permian overall portfolio, what percent of your well could have the opportunity to be three 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?

Thank you for your questions. We do not have a count of our three-mile inventory, and it will be a minor part of our overall program. Most of our land is either developed or designated for two-mile wells, making three-mile wells an exception. In the future, you may see a project or two, with the Marcellus likely hosting the majority of our three-mile wells since that area is fully open for development. However, three-mile wells in the Permian will be uncommon. Regarding the larger project size and its impact on our ability to apply learned experiences, I believe I understand your concern. This situation presents both challenges and opportunities. The larger 51-well program allows us ample chances for control and experimentation. When working on a smaller project, tweaking parameters can make it hard to draw accurate comparisons without a controlled experiment. With a 51-well project, we can implement several subtests, helping us ensure more accurate conclusions by controlling geological and other variables that could otherwise skew our results. It's a great question, and we are confident in our readiness for a project of this magnitude. We look forward to delivering remarkable outcomes.

Your next question is from Noel Parks of Tuohy Brothers.

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 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?

Yes, this is Blake. I'll address your question about Waha. Although Waha has faced challenges in the past, it has shown significant improvement this year, partly due to new expansions coming online and updated forecasts from the Permian indicating a stronger outlook. There are many viable options to transport Permian gas to LNG, and we are considering all of them, although we haven't found the right fit for us yet. In the Marcellus, we have the potential for growth if we decide to pursue it. We are aware of the pipelines available to transport gas, and while it may involve slightly higher costs than what we're currently experiencing, we have accounted for that in our economic assessments.

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

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

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 two 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.

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