Coterra Energy - Q2 2023
August 8, 2023
Transcript
Operator (participant)
Thank you for standing by. At this time, I would like to welcome everyone to the Coterra Energy second quarter 2023 earnings call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number 1 on your telephone keypad. If you would like to withdraw your question, again, press star one. Thank you. Dan Guffey, Vice President of Finance, Planning and Analysis, and Investor Relations, you may begin your conference.
Dan Guffey (VP of Finance, Planning and Analysis and Investor Relations)
Thank you, Cheryl, 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.
Tom Jorden (Chairman, CEO and President)
Thank you, Dan, 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 continue to moderate slightly. Not as significantly as we had hoped. Slide 12 in our investor deck shows that although we look ahead to a 10%-15% reduction in some big-ticket items, we foresee a net 5% reduction in total well costs 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 discipline, 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 in 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 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're confident in our ability to deliver on our updated three-year outlook, as shown on slide five 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 bitter, bittersweet, for 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 advisor 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.
Shane Young (EVP and CFO)
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 36-45 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-$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. 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 has 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%+ 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 from the Company's 2023 crude capital estimate of $2 billion-$2.2 billion. While we are currently trending 1%-2% above the midpoint of our guidance range, we are seeing clear signs of future costs 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 91-94 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%-5%, 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 two rigs and one 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 seven-well Evans development, which is expected to come online during the fourth quarter. We are running one 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 six rigs and three frac crews, one 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 volume. 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-$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 2023-2025 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.
Operator (participant)
To ask a question, please press star one. Please limit yourself to 1 question and 1 follow-up. Your first question is from Nitin Kumar of Mizuho Securities. Please go ahead. Your line is open.
Nitin Kumar (Managing Director, Senior Energy Equity Research Analyst)
Great. Thanks for taking my questions. First of all, congratulations, Scott, on your retirement, and congrats, Shane, on the new role. I, 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 well 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 kinda what leads to this guide?
Tom Jorden (Chairman, CEO and President)
Yeah, Nitin, it's completely project timing and when projects come on. You know, we're in the, in the process of bringing online what we call our Mint Julep Row, which is 23 wells. So the timing of when those come on as we complete that row is strongly driving our production cadence. We've got a nice project, our Red Hills asset in New Mexico, that will come on over the third and fourth quarter. You know, we also in the second quarter had a nice, pleasant surprise with the overperformance of a 3 Mile project, 4 wells in Reeves County. It's completely project timing. Our productivity is surprising us significantly to the upside, 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 (Managing Director, Senior Energy Equity Research Analyst)
Got it. Thanks for the answer, Tom. I guess as my follow-up, I want to touch a little bit upon the cash return. You know, we saw you, against a tough commodity tape, dip into the cash balance a bit and, and return, I think it was 185% of free cash flow. Could you talk a little bit about how do you see? You know, 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 are you looking at it sort of, longer term?
Shane Young (EVP and CFO)
Yeah. Thank you. I'll, I'll take that. listen, you know, when I'd say on the return of capital program, first of all, the, the company looks at it from a, a full year program cycle, and, and focusing on quarter to quarter, certainly make decisions, but I think we try to keep a, a vision of the totality of it in, in mind. You know, if you look back over time, we've maintained a cash balance over the last six quarters as high as almost $1.5 billion, as low as in the $600 million. I think that's a range the company is comfortable operating within.
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.
Nitin Kumar (Managing Director, Senior Energy Equity Research Analyst)
Got it. Great. Thanks, guys.
Operator (participant)
Your next question is from Arun Jayaram of JPMorgan Chase. Please go ahead. Your line is open.
Arun Jayaram (Research Analyst)
Yeah, good morning, gentlemen. I wanted to get some more details on the, on the, the slight change in your three-year outlook. You now you're highlighting the potential to drive annual oil growth above 5%, which it was 5% below before that. What is driving that in a slight change, and does that contemplate the potential reinvestment of $200 million, call it, from the Marcellus to your two other oil plays?
Tom Jorden (Chairman, CEO and President)
Yeah, yeah, Arun, it's well productivity is driving that change, purely and simply. No, we're, there's no assumption of reallocation in that three-year plan.
Arun Jayaram (Research Analyst)
Understood, Tom. What would, you know, as you, you and your team look at the 2024 outlook, you know, 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?
Tom Jorden (Chairman, CEO and President)
No, I would not say.
Arun Jayaram (Research Analyst)
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, fair enough?
Tom Jorden (Chairman, CEO and President)
That's correct. Thanks, Arun.
Arun Jayaram (Research Analyst)
Okay.
Operator (participant)
Your next question is from Umang Choudhary of Goldman Sachs. Please go ahead. Your line is open.
Umang Choudhary (Research Analyst)
Hi, good morning, and thank you for taking my questions. Also congratulations, Scott, for your retirement.
Tom Jorden (Chairman, CEO and President)
Sure.
Umang Choudhary (Research Analyst)
We will miss you. Shane, congratulations. Look forward to working with you. Let me-- thank you. Let me start with the cost deflation point. 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 this cost savings? Then, to be sure, this is not incorporated in your three-year outlook.
Blake Sirgo (SVP of Operations)
Yeah, this is Blake. I'll take that one. You know, really what we're trying to show on, on slide 12 is how our cost structure is and is not moving throughout 2023. When we built the budget, we, we had some strong indications that our leading cost indicators were coming down, and most of those have come to fruition. You can see with our mid-year repricings, we, 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. That part's been pretty sticky. It's a bunch of smaller services really underpinned by labor and fuel, and we just haven't seen that deflation there.
All we're assuming when we do the 5% is that those leading-edge indicators on those services we've called out maintained for a full year, whereas this year, we only got to realize them for half a year.
Umang Choudhary (Research Analyst)
Gotcha, that makes sense. Then, I just wanted to go back to the three-year outlook. I, 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? How does that change your thoughts around, you know, long-term capital spending?
Tom Jorden (Chairman, CEO and President)
Well, certainly we'll drill more productive wells, and I, with our operations team, we will achieve increasing operational efficiencies. You know, we, as we 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, you know, it's going to be stunningly productive. You know, I'll say as, 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. You know, there is always a bit of wanting to skate where the puck's going tobe on commodity pricing. We're going to be disciplined.
We're not going to chase the strip, as I said, but, you know, 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 can be destructive to your well productivity, it can be destructive to your operational efficiency, and you can exactly time it wrong. Consistency is a luxury that Coterra affords, and we, we intend to exercise it.
Umang Choudhary (Research Analyst)
Makes a lot of sense. Thank you.
Operator (participant)
Your next question is from Doug Leggate of Bank of America. Please go ahead. Your line is open.
Doug Leggate (Managing Director, Head of Global Oil and Gas Equity Research)
Thanks. Good morning, everyone. 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 2021, you were at about 35%, 36% natural gas yield. End of last year, it was 34%, 1st quarter was 32%, this quarter is 31%. Is there something going on there, or is it just a function of flush oil production?
Tom Jorden (Chairman, CEO and President)
If there's some overprint of it we're not aware of, I think it's, 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. Overall, we see a fairly consistent analysis of our assets. Blake, you want to comment on that?
Blake Sirgo (SVP of Operations)
Yeah, I'd just say our, our program's driven by constantly high grading. In the Permian, that means our oiliest projects come to the front. Our teams do a great job of that. I'm, I'm not surprised that it looks good.
Doug Leggate (Managing Director, Head of Global Oil and Gas Equity Research)
Okay, I, I just wondered if it was something different about what you guys were doing, but thank you for that. My, my follow-up is really a clarification question on the, the earlier comment, excuse me, about spending. Shane, you touched on the Marcellus, and your activity level obviously dropped earlier this year.
Neal Dingmann (Managing Director)
Understanding everything Tom said about accepting the, you know, the, the growth as an output, it sounds like you're signaling that for the current level activity, your, your CapEx could reasonably be in the $1.9, maybe even lower range. Am I, am I reading that wrong, or can you just elaborate a little bit on what you were trying to signal there?
Tom Jorden (Chairman, CEO and President)
Yeah, look, I think what I was trying to say is we currently have two rigs running and, and 1 crew in the Marcellus. 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. I think that's, that was sort of the message that we were trying to deliver based on where activity is today.
Neal Dingmann (Managing Director)
That holds you flat in the Marcellus?
Tom Jorden (Chairman, CEO and President)
That holds production flat in the Marcellus.
Neal Dingmann (Managing Director)
Great. That's what I needed. Thank you, guys. Appreciate the answers.
Operator (participant)
Your next question is from Michael Scialla of Stephens. Please go ahead. Your line is open.
Michael Scialla (Managing Director, Energy Equity Research)
Yeah, good morning, everybody, I'll offer my congratulations to both Scott and Shane as well. I'm 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, 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?
Tom Jorden (Chairman, CEO and President)
Y-yeah, Mike, you know, we've got a wide range of investors, as you can imagine. We, we have differing voices. I, you know, quite frankly, we have some investors that tell us that if anybody's earned the right to grow, it's this team. We have other investors that are-- feel differently. We always enjoy conversations with our investors and getting feedback, and we'll certainly be doing that on the heels of this call. I think the, 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, you know, that's what we're here to do.
Michael Scialla (Managing Director, Energy Equity Research)
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 where do the potential savings, where do those come in, and maybe the timing of getting those wells online?
Tom Jorden (Chairman, CEO and President)
Yeah. I'll, start it out, and I'll let Blake take it home. You know, 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 a way that manages the reservoir. It's, it's just really everything that the last decade has led up to in terms of taking advantage of our own technical innovations. Blake, you want to say anything?
Blake Sirgo (SVP of Operations)
Yeah, sure. you know, 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 six distinct drill spacing units and prosecuting them in one consistent row. No, big changes on wells per section or completion design. This is all about concentrating activity to maximize efficiency. All those things Tom said, we're cutting down on mobes. We're parking frac rigs where they can get the most pump hours per day. We're centralizing and co-mingling facilities and infrastructure. When you bring all that together, all those efficiencies really add up. As we model this project, our $ per foot is coming in about 8% lower than our current Culberson average. That's just the power of all that.
What our Permian team's really doing is executing efficiencies on a grand scale coming to bear.
Tom Jorden (Chairman, CEO and President)
Yeah, 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's completed. We stage them online continuously as we're continuing to drill and complete.
Michael Scialla (Managing Director, Energy Equity Research)
That's helpful. Thank you.
Operator (participant)
Your next question is from Neal Dingmann of Truist Securities. Please go ahead. Your line is open.
Neal Dingmann (Managing Director)
Morning. Thanks for the time. Scott, thanks for everything. It's been great working with you. My question first is on OFS costs. Specifically, could you guys just talk maybe, you know, we hear a lot about cost deflation and OCTG and all those things. I'm just wondering, Tom, maybe more or less how you all think about spot versus long-term contracts. I know you've, you know, in the past had some opinions. How you think about the two. Is there a big pricing difference between the two today?
Tom Jorden (Chairman, CEO and President)
Well, it depends on the, the particular item you're speaking of. You know, 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. You know, as you know, we, we really try to avoid long-term commitments because it limits our flexibility. 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, we know for sure that we will have three rigs running. We may have three of them on a 1-year contract and three of them on, month-to-month.
We really try to balance the value of the commitment against the value of the flexibility. Blake, you want to say anything about that?
Blake Sirgo (SVP of Operations)
I, I think you nailed it. It's, it's all about the value proposition. You know, not, not a year ago, we were signing contracts to hopefully keep inflation from rising. Today, we're looking at contracts where we could see deflation if we entered into longer-term deals. So we just have to balance those things 'cause they can reduce our flexibility, and that's what we run the downside cases for.
Leo Mariani (Managing Director, Senior Research Analyst)
No, great, great color. Then if I could just on the last one, maybe a little bit on, on what, what Mike 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?
Tom Jorden (Chairman, CEO and President)
Well, well, it's in Culberson County. It's in sort of the south central Culberson County on the eastern side. We call it the Windham Row, named after our landowners out there, but it's, it's in a great area. It's well-defined. We've got a lot of calibration. It's good reservoir, good pressure, good oil. I mean, it's, it's, it's ready to roll.
Leo Mariani (Managing Director, Senior Research Analyst)
Perfect. Look forward to that one. Thanks, guys.
Operator (participant)
Your next question is from Derrick Whitfield of Stifel. Please go ahead. Your line is open.
Derrick Whitfield (Managing Director and Senior Analyst)
Good morning. Congrats to both Scott and Shane as well. Tom, with regard to your Q2 production beat, you noted better-than-expected well performance and 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?
Tom Jorden (Chairman, CEO and President)
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 a slightly different viewpoint than some of our competitors on the impact of the what it's called cube drilling, or some people call it tank development, and how to manage that. Really, it's, it's, it's a, it's a sum of a lot of innovations over time. I also want to credit our machine learning team.
I, I know you know, a call doesn't go by where I don't say something about machine learning, but it's, it's really been transformative and become a very, very trusted partner with our operations teams and project planning. It's changed our thinking on some of the ways these parameters interact. Blake?
Blake Sirgo (SVP of Operations)
Yeah, I would, well, spacing and frac design are a never-ending topic at Coterra. We debate them constantly, and we don't ever settle that the current design is the best, so it's, you're seeing that across the portfolio this year.
Derrick Whitfield (Managing Director and Senior Analyst)
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, the relative allocation of capital in the Permian over the next three years if results are as you guys expect?
Tom Jorden (Chairman, CEO and President)
I, 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, I, I don't... I think it will help us to optimize based on what we, we learn. We're continuously trying to optimize, but I don't think it would necessarily change our capital allocation.
Derrick Whitfield (Managing Director and Senior Analyst)
Great color. Thanks for your time.
Operator (participant)
Your next question is from Roger Read of Wells Fargo. Please go ahead. Your line is open.
Roger Read (Senior Energy Analyst)
Yeah, thank you. Good morning. I'm going to come back and hit some of the, the same, let's call it capital efficiency, productivity questions that have been asked. If you step back and look across, and, you know, you do have a, different collection of assets than some of the other, companies in, in terms of being a pure play. If 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?
Tom Jorden (Chairman, CEO and President)
Oh, I, I think all three are ripe 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, in field. You know, there's, there are a lot of challenges in the Marcellus that are unique to the Marcellus. A lot of challenges are unique. I would say our operating teams across our platform are learning from one another in a lot of that operational optimization, but we really see opportunity everywhere we look. Blake, you want to add to that?
Blake Sirgo (SVP of Operations)
Yeah, just saying the Marcellus, our, 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 wells with total measured depth in excess of 25,000 feet. Pretty lights out performance that's really helping drive down our cost per foot. In the Permian, you know, it's, 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, we expect that to continue.
Roger Read (Senior Energy Analyst)
Okay, fair to say scale, big contributor in the Permian. Scale of any-
Blake Sirgo (SVP of Operations)
Correct
Roger Read (Senior Energy Analyst)
... individual development or pad. Okay.
Blake Sirgo (SVP of Operations)
Well, yeah.
Roger Read (Senior Energy Analyst)
Sorry, go ahead.
Blake Sirgo (SVP of Operations)
We have a fit. Our, our drilling and completion feet per day are up also. I mean, our, our crews are hitting records on pumping hours per month. Our drilling feet per day is up 14% this year, but that, that's what we expect. That's what we do every year.
Roger Read (Senior Energy Analyst)
Okay, appreciate that. Then follow-up question, I'm going to apologize for asking two parts within one question, but they, they go together, so, roll with me if you would. The CapEx looks like it's going to be above the midpoint for 2023. It sounds like everything's pointing to lower in 2024. I was just hoping you could give us a little, you know, a nugget here or there as to, you know, why we should have confidence that a potential outspend, even if only marginal in 2023, doesn't carry through to 2024.
Blake Sirgo (SVP of Operations)
Yeah, I, I think, you know, that's why we gave slide 12 to kind of give some color on deflation. When we, 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'd feel very confident we'd be at the low end of the range, but it, it just hasn't materialized. We're seeing it on a few leading items, but not through the whole cost structure. When we give the 5% going into 2024, all that assumes is the gains we've got so far this year continue, and nothing else.
Roger Read (Senior Energy Analyst)
Okay, could I ask one follow-up on the current deflation? What, what percentage is related to logistics or diesel costs or anything like that? Just noting that, you know, oil has gone back up to the mid-80s, and fuel prices have followed to some extent.
Blake Sirgo (SVP of Operations)
Yeah, I don't, I don't have that exact call out. I can tell you it's-
Roger Read (Senior Energy Analyst)
All right.
Blake Sirgo (SVP of Operations)
pretty much baked into all our services.
Roger Read (Senior Energy Analyst)
We'll, we'll follow up. Thank you.
Operator (participant)
Your next question is from Kevin McCurdyof Pickering Energy Partners. Please go ahead. Your line is open.
Kevin MacCurdy (Director)
Hey, good morning. 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 OpEx, especially given the lower volumes outlook?
Blake Sirgo (SVP of Operations)
I'd say our LOE is down quarter-over-quarter, so that's, that's the big one. We, 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, we're hitting those caps this year. We've modeled that out, and as you can see in our full cost, we're, we're front loaded and expect to come in in the middle of the range.
Tom Jorden (Chairman, CEO and President)
I, I would just make sort of on, on, on cash costs, sort of as, as we highlighted for the quarter. You know, in addition to LOE, overall, we're down from $8.90/BOE last quarter, down to $8.27/BOE this quarter. I think we're feels like we're trending in the right, the right area.
Kevin MacCurdy (Director)
Okay. Digging into the production guide a little bit, you mentioned that the 3-mi laterals were outperforming your expectations and that you're seeing some improvement to cycle times. Just kind of curious, how do you risk those two items when calculating your third quarter and fourth quarter guidance?
Tom Jorden (Chairman, CEO and President)
Well, based on our experience with long laterals, I mean, you know, long lateral performance is something that we're all still learning. As we went from 1 mile to 2 mile horizontal wells, we, we had to learn what the uplift from one to two is. It's depending on the reservoir, depending on the spacing, depending on the nature of the flow back. You know, although we have some experience with 3-mile laterals, we don't have broad experience in any one area. We've, we've got a, you know, a 3-mile project in several different areas. This one was in Reeves County, where the operating environment is so different and, you know, just quite frankly, the well surprised the upside.
I mean, I, wish I had some grand conclusion, but, it, just they, they flowed back a little stronger and with a little more uplift over a 2 mile than we had forecast.
Kevin MacCurdy (Director)
Great. Thank you for taking my questions, and congratulations on the good production beat.
Operator (participant)
Your next question is from Leo Mariani of Roth MKM. Please go ahead. Your line is open.
Leo Mariani (Managing Director, Senior Research Analyst)
I just wanted to stick with some of the, the line of questioning here on well productivity. I mean, I think that the one that kind of stood out to me was the Marcellus in the, in the second quarter. Material increase on the production, you know, 9%. You know, typically, I guess, I, you know, I tend to think of the Marcellus as being, you know, sort of an older, more mature play, where there's probably not a tremendous amount of, of sort of tweaks and improvements that, that can sort of be had here. It certainly looks like maybe that wasn't the case here, you know, in the second quarter, and it didn't seem like there was some outsized number of wells that, that came online. Just seems like some, some outsized production growth. Can you maybe.
Paul Cheng (Managing Director, Senior Equity Analyst)
Give us a little bit more color around why the Marcellus was particularly strong in the second quarter?
Tom Jorden (Chairman, CEO and President)
Well, I would say that our team is really hitting their stride. We, we have a fantastic operational team, both in the office and in the field when it comes to Marcellus. The team has done a lot to manage and understand parent-child effects and really tailor our completions around that, tailor our well spacing. They've really done a great job in revising our forecast methodology. You know, we're forecasting much more accurately. Just, you know, 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. You know, 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, you know, it's almost everything coming together at once. They're doing a tremendous job.
Paul Cheng (Managing Director, Senior Equity Analyst)
Okay, that's helpful. Just kinda, you know, turning to CapEx, you guys said you're probably going to end up being 2% over the midpoint here, you know, in, in, in 2023. As I kinda looked at the, you know, sort of accrual numbers, and maybe you're looking at the cash numbers as you're kinda getting to that. Maybe you could kind of, you know, let us know if that's kind of accrual versus cash. I think in either case, it implies a pretty healthy downturn, in, in fourth quarter CapEx, you know, something maybe closer to the $500. I just want to make sure I'm reading that right, on the capital, into 4Q.
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 2023?
Shane Young (EVP and CFO)
Hey, Leo, Shane here. Listen, yeah, as it relates to 2023 and, and the, the guidance range for the accrual is 2-2.2. What we said is, we think we're trending presently at 1%-2%, sort of above the midpoint within that range. 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, you know, 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, you're absolutely right. You know, maybe even a little lower than the numbers you're referencing, at the midpoint when, 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. That's what's really leading to the lower activity that leads to the lower accrued CapEx.
Paul Cheng (Managing Director, Senior Equity Analyst)
Thank you for the answer.
Operator (participant)
Your next question is from Paul Cheng of Scotiabank. Please go ahead. Your line is open.
Paul Cheng (Managing Director, Senior Equity Analyst)
Thank you. Good morning, gentlemen. Tom, you, you mentioned that you benefit from the 3 miles well in the second quarter. Could, could you give us an idea that how many of the 3-mile well that you're going to drill for the next, say, two or three-year program? Also in your Permian overall portfolio, what percent of your well could have the opportunity to be 3, 3 miles? That's the first question. The second question is talking about the larger pad. You, larger size pad that you expect to increase further.
How, how you, maybe manage between, the better economy of scale with the larger pad, but also that, maybe reducing the flexibility of the instant learning curve, going back into, the, tcompletion design and everything, given that it's larger pad size? Thank you.
Tom Jorden (Chairman, CEO and President)
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. You know, 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 two. 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, it's going to be a rare instance. Then, you know, 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, you know, that's that is a two-edged 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. You know, one of the things that is vexing 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, to compare it to. With a 51 well project, we'll have the opportunity to have several sub-tests within that, have good offset control, and really normalize out some of the geologic and other attributes that can cloud your conclusions. You know, it's a good question. We, we think that we're ready for a project this size, and we do really look forward to delivering outstanding results with it.
Noel Parks (Managing Director, CleanTech and E&P)
Thank you.
Operator (participant)
Your next question is from Noel Parks of Tuohy Brothers. Please go ahead. Your line is open.
Noel Parks (Managing Director, CleanTech and E&P)
Hi, good morning.
Blake Sirgo (SVP of Operations)
Morning.
Noel Parks (Managing Director, CleanTech and E&P)
I wondered if you could talk a bit about your, your thoughts on sort of the, the risk-reward of infrastructure investment going forward from here. Thinking in particular about this lull we're in with gas prices, oil strengthening, and that makes me think, of course, about the Permian and associated gas. I feel like there's, there's somewhat mixed signals about how that might fare with the, the LNG uplift on the horizon. So just between Marcellus position and of course, being in the Permian, just your, your thoughts on maybe what infrastructure priorities might look like heading into LNG.
Blake Sirgo (SVP of Operations)
Yeah, this is Blake. I'll take that one. You know, your first question around Waha. You know, Waha has traditionally been pressured, but we've, 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. There's, 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 one that works for us yet. Up in the Marcellus, you know, 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.
Scott Schroeder (EVP and CFO)
Okay. Okay, fair enough. 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, you know, from basin to basin? Are in 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 (SVP of Operations)
Yeah, this is Blake. I, 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. In general, we have great service partners we've been with a long time, and we, we work together through ups and downs.
Scott Schroeder (EVP and CFO)
Okay, great. Thanks a lot.
Operator (participant)
There are no further questions at this time. I will now turn the call over to Tom Jorden for closing remarks.
Tom Jorden (Chairman, CEO and President)
Well, thank you, everyone, and I'd like to turn the call over to Scott for some closing remarks.
Scott Schroeder (EVP and CFO)
Thank you, Tom, and thank you, everyone. It's been a tremendous ride. I'm, I'm extremely proud of what we've 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's 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 (participant)
This concludes today's conference call. Thank you for our participation. You may now disconnect.
