Coterra Energy Inc. (NYSE:CTRA) Q1 2024 Earnings Call Transcript

Coterra Energy Inc. (NYSE:CTRA) Q1 2024 Earnings Call Transcript May 3, 2024

Coterra Energy Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good morning. My name is Audra, and I will be your conference operator today. At this time, I would like to welcome everyone to the Caterra Energy, Inc.’s First Quarter 2024 Earnings Conference Call. Today’s conference is being recorded. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks there will be a question-and-answer session. [Operator Instructions]. At this time, I would like to turn the conference over to Dan Guffey, Vice President of Finance, Investor Relations and Treasurer. Please go ahead.

Daniel Guffey: Thank you, Audra. Good morning, and thank you for joining Coterra Energy’s first quarter 2024 earnings conference call. Today’s prepared remarks will include an overview from Tom Jorden, Chairman, CEO and President; Shane Young, Executive Vice President and CFO; and Blake Sirgo, Senior Vice President of Operations. 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.

A – Thomas Jorden: Thank you, Dan, and welcome to all of you who are joining us on the call this morning. We’re pleased to report that Coterra had an excellent first quarter. Our total equivalent production for the quarter was 686,000 barrels of oil equivalent per day, which was near the high end of our guidance. Oil production averaged 102.5 thousand barrels of oil per day, which was 3,500 barrels of oil per day above the high end of our guidance. This beat in oil production was driven by a combination of well performance that exceeded expectations, production optimization and timing. Natural gas production averaged 2.96 billion cubic feet a day, which was slightly above the high end of our guidance. Capital expenditures came in at $450 million, which was below the guidance range.

This was a combination of timing and cost reductions and completions. Blake will provide further detail on this. We have raised our full-year oil guidance, while leaving our natural gas guidance unchanged. Shane will provide commentary here. As we previously said, our capital guidance for 2024 includes room for adding additional Marcellus activity, if our received prices in the Marcellus were to rebound. Of course, any additional activity will be evaluated against other shovel-ready opportunities in our portfolio. Rapid and severe commodity price swings are a feature of our business. As much as we try to anticipate and predict market movements, there is an inherent humbling unpredictability to them. During Q1, we saw upward movement in oil, coupled with downward movement in gas.

Despite these swings, revenue at Coterra for Q1 2024 came in roughly flat with revenue for Q4 2023. This stability in revenue allows us the luxury of maintaining a consistent level of activity, while retaining significant upside exposure to a gas price recovery. We did, however, delay some Marcellus turn-in-lines during Q1. We currently have two pads comprising 12 wells completed and waiting to be brought online. We have ongoing completion activity and are making the go/no-go decision on bringing wells online on a monthly basis. Blake will provide further detail on this. In spite of near-term headwinds, we remain wholly optimistic on natural gas. With coming LNG export capacity, near-term power demand and the evolving discussion about the long-term power demands of AI-driven data center needs, it is hard not to be constructive on the future of natural gas.

We watch this conversation closely and have heard forecast for incremental natural gas demand driven by growing data center consumption that range from 3 Bcf per day to 30-plus Bcf per day, by the year 2030. We will welcome increased demand anywhere within that range. Finally, we are pleased to once again be reporting results that exceed expectations. Our organization is highly focused on operational excellence, costs, safety, emission reduction and on being responsible members of our communities. I want to acknowledge the tremendous work and dedication of our entire organization from the field on up. This includes, in addition to field office staff, contractors, and service partners. At Coterra, we continually choose progress over comfort.

And our strong culture of optimization, innovation, and financial discipline continues to be an important competitive advantage. With that, I’ll turn the call over to Shane.

Shane Young: Thank you, Tom, and thank you everyone for joining us on today’s call. This morning, I’ll focus on three areas. First, I will summarize financial highlights from the first quarter results, then I will provide production and capital guidance for the second quarter, as well as update our full-year 2024 guide. Finally, I’ll provide highlights for our recent bond offering and the progress we’re making on our shareholder return program. Turning to our strong performance during the first quarter. First quarter total production averaged 686 MBoe per day, with oil averaging 102.5 MBO per day and natural gas averaging 2.96 Bcf per day. Oil and natural gas production came in above the high end of guidance, driven by strong well performance and a modest acceleration of Permian TIL timing.

In the Permian, we brought on 22 wells versus 21 wells at the midpoint of our guidance. In contrast, in the Marcellus, we tilled 11 wells below our guidance of 23 wells. I will discuss this further later in my remarks. During the first quarter, pre-hedge revenues were approximately $1.4 billion, of which 62% were generated by oil and NGL sales. In the quarter, we reported net income of $352 million or $0.47 per share and adjusted net income of $383 million or $0.51 per share. Total unit costs during the quarter, including LOE, transportation, production taxes and G&A totaled $8.68 per BOE, near the midpoint of our annual guidance range of $7.45 to $9.55 per BOE. Cash hedge gains during the quarter totaled $26 million. And current capital expenditures in the first quarter totaled $450 million, just below the low end of our guidance range.

Lower-than-expected capital was driven primarily by timing and we are maintaining our full-year capital guide. Discretionary cash flow was $797 million, and free cash flow was $340 million after cash capital expenditures of $457 million. Looking ahead to the remainder of 2024. During the second quarter of 2024, we expect total production to average between 625 and 655 MBoe per day, oil to be between 103 and 107 MBO per day and natural gas to be between 2.6 and 2.7 Bcf per day. In other words, we expect oil to be up approximately 2.5% quarter-over-quarter on continued strong execution. Regarding investment, we would expect total incurred capital during the second quarter to be between $470 million and $550 million. As a result of low natural gas prices, we have chosen to defer the turn in line of two separate Marcellus projects totaling 12 wells.

Based on current in-basin pricing, we don’t anticipate bringing any projects online in the Marcellus during the second quarter, resulting in lower gas volumes quarter-over-quarter before flattening in the second half of the year. Yesterday, we increased our full-year 2024 oil production guidance range by 2.5 MBO per day to between 102 and 107 MBO per day for the year or up approximately 2.5% from our initial guide in February. There is no change to our full-year 2024 BOE and natural gas production guidance. Similarly, there are no changes to our unit cost guidance or turn in well — turn-in-line well counts for the year. For the full-year 2024, we are reiterating our incurred capital guidance to between $1.75 billion and $1.95 billion, which is 12% lower at the midpoint than our 2023 capital spend.

As previously discussed, our 2024 program will modestly increase capital allocation to the liquids-rich Permian and Anadarko Basins, while decreasing capital by more than 50% in the Marcellus year-over-year. Moving on to shareholder returns. As previously announced, during the first quarter, we successfully issued Coterra’s inaugural bond offering of $500 million of senior notes carrying a coupon of 5.6% and a maturity of 2034. We were pleased with the timing of the transaction and the reception of the Coterra story in the market. We intend to use the proceeds of this offering along with cash on hand to retire our $575 million 2024 notes at maturity during the third quarter. Until the maturity, we have invested the proceeds and time deposits at a similar interest rate to the coupon of the notes.

Coterra continues to maintain its low leverage profile with a ratio of 0.3x at the end of the first quarter. Our target leverage ratio remains below 1x even at lower price scenarios. This refinancing allowed us to extend our maturity profile, maintain a high liquidity position and affords us modest deleveraging, while maintaining a robust shareholder return program in 2024. During the first quarter, Coterra continued to execute on its shareholder return program by repurchasing 5.6 million shares for a $150 million at an average price of $26.94 per share. In total, we returned $308 million to shareholders during the quarter or over 90% of free cash flow. We remain committed to our strategy of returning 50% or more of annual free cash flow to shareholders through a combination of our healthy base dividend and our share repurchase program.

Last night, we also announced a $0.21 per share base dividend for the first quarter, maintaining our annual base dividend at $0.84 per share. This remains one of the highest yielding base dividends of our peers at approximately 3%. Management and the Board remain committed to responsibly increasing the base dividend on an annual cadence. In summary, the team delivered another quarter of high-quality results in the field, which resulted in another successful quarter financially. Our business has significant operating momentum and we are poised for a strong 2024 and are on track to meet or exceed the differentiated three year outlook we provided in February. With that, I will hand the call over to Blake to provide details on our operations. Blake?

Blake Sirgo: Thanks, Shane. This morning, I will discuss our capital expenditures and provide an operational update. First quarter our crude capital expenditures totaled $450 million, coming in just below the low end of our guidance. Our strong execution in the field continued in Q1 with our oil production coming in at 102.5 thousand barrels of oil per day above the high end of our guidance. We are seeing continued completion gains in the Permian, led by reduced transition times on our diesel crew as well as strong initial performance from our electric simul frac crew in Culberson County. During the first quarter, our two Permian crews and one Anadarko crew hit all-time highs in efficiency with record pumping hours per month.

These efficiencies are coupled with new contracts that ensure when we gain efficiencies, it is realized in our dollar per foot and not just in our cycle times. We are currently running two frac crews and eight drilling rigs in the Permian. We continue to benefit from operational efficiencies, including cost savings on electrification, leveraging existing facilities and infrastructure as well as improved cycle times. Faster cycle times drives more footage in the year, also contributing to lower dollar per foot. As a result, we estimate our Permian cost around $10.75 per foot, roughly 8% below our 2023 per foot. Our Windham Row project is off and running with 34 wells now drilled and our simul-frac operations underway. Our electric simul-frac crew is powered directly off our Coterra-owned grid with no generation in the field required.

We are seeing encouraging initial performance from our simul-frac crew with an increase of 1,000 completed feet per day versus our normal zipper performance with a decreased cost of $25 per foot. When we combine our simul-frac efficiencies with the current cost spread between diesel and grid power, we are realizing a total cost savings of $75 per foot, compared to current diesel-powered zipper operations. One update to the Windham Row project is the addition of three Harkey wells to the western part of the Row, bringing the project total to 54 wells. Recent tests in our Culberson asset have shown a possible benefit to co-developing the Upper Wolfcamp with our Harkey Shale landings. This observation is different than what we’ve seen with our other Harkey projects across the basin.

And these three new codeveloped wells will help us further understand the interaction between these zones. Due to strong execution on the project so far, we were able to fit these three new wells to our existing schedule without incurring additional facility or infrastructure costs. As previously discussed, we expect to execute large Row development for many years to come in Culberson County. Our Permian team continues to build momentum and is off to a strong start in 2024. In the Marcellus, we are currently running one rig and one reduced frac crew. Our focus in the Marcellus continues to be decelerating activity and reducing costs as near-term gas markets remain challenging. Our Marcellus program is buoyed by our long-term sales portfolio, which contains multiple indices and price floors, which come into play at lower NYMEX pricing.

We currently have two pads consisting of 12 wells in total that we are delaying turn-in lines. Each incremental molecule we bring on receives in-basin price compared to the rest of our portfolio. Therefore, we are choosing to delay these TILs until we see stronger local pricing. We have also chosen to delay a portion of our well head compression program into 2025, so as not to accelerate volumes into a weakened market. Our teams are focused on reducing costs in the field and looking for ways to optimize our capital spend. As we have discussed, our Marcellus business unit has several strong projects that are teed up and ready to execute later in the year, should macro conditions warrant. In the Anadarko, we are currently running two rigs and one frac crew.

We are in the middle of a large block of completion activity, with three projects being fracked over the first half of 2024. These projects are focused on liquids-rich portions of our asset, which maintains strong economics in the current gas environment. Our consistent activity in the Anadarko is starting to bear fruit. As we have seen our drilled feet per day increased 15% year-over-year, as well as an increase of 10% in pumping hours per day compared to a year ago. Our Anadarko team continues to compete for capital and the returns across the basin remains strong. Our operating teams at Coterra are firing on all cylinders. We continue to make positive strides across all areas of operations, including new initiatives that are materially reducing well trouble costs, minimizing production downtime, beating our emissions targets, improving our cycle times and gaining new efficiencies.

Our field operations are the heartbeat of our company, and they continue to fuel our momentum. And with that, I’ll turn it back to Tom.

Thomas Jorden: Thank you, Shane and Blake. We’re pleased with our continued execution momentum as we march through 2024. We appreciate your interest in Coterra and look forward to discussing our results and outlook. As always, we like talking about results, more the future promises, and we’re always pleased to deliver them. With that, we’ll turn it over to questions.

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions]. We’ll take our first question from Nitin Kumar at Mizuho.

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Q&A Session

Nitin Kumar: Hey, good morning Tom and Shane, congrats on the great results. Tom, I want to start off in the Marcellus, and you deferred 12 completed wells for later in the year. The plan still calls for about 29 wells to be put online. Could you maybe talk us through how are — what are the market conditions? Is there a specific price? Or is there a supply or demand equation that you’re looking at to, one, bring on the 12 wells? And two, how would you think about the rest of the program for the year?

Thomas Jorden: Thank you, Nitin. Well, first, I’m going to say if there’s a specific price or a complex formula, nobody has shared that with me yet. But we’re looking at our received price. And quite frankly, we sell into indices. [indiscernible] is the one that we typically point to. And when it’s — I would say, when it’s sub $1.50, we really look at that and we say, okay, what’s the outlook for that? And we do have transportation and LOE that comes off of that. And I wouldn’t say there’s a particular pricing. But I’ll say this, we do have a very low cost of supply. But I think we probably would like to see our netback north of $1. And so we’re watching that. We’re making it, as I said in my remarks, we’re making that on a month-to-month go-no-go basis.

We are current model has us bringing additional wells online in July. Whether we do that or not, we’re optimistic, but we’re not going to be driven by our model. It will be driven by the way the terrain looks on the ground. I want to say that there’s two issues, when you ask what price. There’s the price for when we bring wells online, but is also the price of when we would increase our investments. As I said, our capital program has room for a ramp-up. And if we were to do that, we really see a strong rebound in our volumes going into 2025 and ’26. And that’s a whole different price comparison. But as I said, we’re really constructive on Natural Gas. But look, we’re in a real hostile near-term environment, and we think just moderating these turn in lines as the way to go.

We’re also going to look and see what others do. There’s a lot of gas, a lot of players doing what we’re doing. And when we bring these wells online, we’re going to be thoughtful and look at the market conditions and if there’s a flood of gas coming online, that may impact our decision.

Nitin Kumar: Great. Thanks for that insight, Tom. And I appreciate that. I want to shift to the Permian and talk about the Windham Row. Could you maybe talk a little bit about what have you seen, obviously, adding a few wells in the Harkey. It is a positive, but — what are you seeing? And what are some of the lessons learned? And if you can walk us through the 5% to 15% cost reduction that you’re seeing, if I think about $1 billion spend in the Permian this year, could we look at something which is 10% less capital spend in the Permian for the same result down the road?

Thomas Jorden: Yes. I’m going to hit the Harkey and let Blake look at the cost reduction. Our general observation in a lot of our Delaware program is that in our assets, our observation has been that whether we exploit these reservoirs one layer at a time or not that we don’t really see any incremental recovery out of a drilling spacing unit. So doing them in stages allows us to really take full advantage of our infrastructure because we can stage volumes in and not have to build facilities for the absolute peak production, because these wells do decline. And if you build your facilities for absolute peak production, you find that they’re very early in the life underutilized. But we did on another project in Culberson County, where things are a little different.

It’s on the western side of the basin, a little lower pressure. We did see on an experiment we did over the last year or two that co-developing the Harkey and the Wolfcamp at the same time versus waiting 12 to 18 months and coming back with the Harkey, I’d say 12 to 24 months. We did see what we think is an incremental boost in recovery. We’re not concluding that, but we prudently added the Row and a few Harkey wells. And I’ll say this, while we continue to learn, I think on new projects, you’re going to see that in Culberson County is probably our default option. As we continue to learn, and we’re not chiseling and granted final conclusions here.

Blake Sirgo: Yes. I’ll take the cost question. When we talk about Windham Row and simul-frac. The simul-frac is going very well. I mean, right out of the gate, the performance has been strong. We were hoping we would see at least $20 per foot. To date, we’ve seen about $25. And there’s room for that to go even further, but we’re early in the game there. We’re watching it very close. As far as how we can expand these learnings, we’re only simul-fracking 27 wells in the Permian this year as part of Windham Row. But with this initial success, our Permian team is looking hard at how we could exploit this across our whole drilling program. I wouldn’t take that and slap a 10% cost change on the whole program because you got to have just the right number of wells per pad to make simul-frac really cost effective, but our teams are looking at that now, and we’re excited to see where it goes.

Nitin Kumar: Great. Thanks for the color guys.

Operator: We’ll go next to Arun Jayaram at JPMorgan.

Arun Jayaram: Yes, good morning. My first question is on cash return. You returned 90% of free cash flow this quarter. But I wanted to get maybe some broader thoughts on just the overall philosophy given your views on the valuation of the stock. You recently issued $500 million of notes to help refund the payment of the $575 million maturity later this year. How did cash return, Tom, attractiveness of the valuation of the stock play into that decision? You have about $1 billion of net cash on the balance sheet today, excluding that recent notes issue. How do we think about the minimum cash balance and perhaps thoughts on leaning in the balance, on the balance sheet in addition to free cash flow to buy back the stock?

Thomas Jorden: Yes, I’ll let Shane handle that one.

Shane Young: Yes, I appreciate the question. I’ll take it. Look, we look at a variety of things. We think about the return program and the pace. And look, you’ve touched on many of them. First and foremost, we look at valuation, and we believe our stock is a compelling valuation. And if so, then we’re going to be inclined to do more there. The second is liquidity and where does liquidity sit and you know what our target is and where we’re sitting above our target as of the end of the first quarter. And then the third is the free cash flow of the business in any given period. And there’s other things, but I think if we triangulate around those, it’s helpful. As we were getting into late last year, we were having a discussion around here about how to handle the 2024 maturity.

And we looked at a variety of scenarios. We had good cash on hand and liquidity. So that was one option to do cash. We had — and as we got into the early part of this year, the market [Technical Difficulty] new issuances of debt and that’s been an option for us, and that ended up being generally speaking, the path that we took. So we’ll be repaying $575 million of debt later this year, largely with the proceeds of the $500 million new issue and a little bit of cash on hand. But not really clarified that question for us is to what kind of impact that maturity could have on our liquidity. And once it did, with a combination of free cash flow and attractive stock price, you saw us lean into the share buyback program in the first quarter.

Arun Jayaram: Great. And Shane, what do you view as the minimum cash you’d like to keep on the balance sheet?

Shane Young: We’ve gone as low as $600 million over the last, call it seven, eight quarters. And again, I think that probably as low as it could go. We target $1 billion. We’ve been as high as $1.4 billion. And I think you’ll continue to see us live somewhere in that range. It’s a broad range. But I think you’ll continue to see us reside within that range.

Thomas Jorden: So Arun, if I could just add some color. We have relaxed a little bit our $1 billion number on cash on the balance sheet. We have plenty of liquidity. Our buyback is really because we see value in our stock, quite frankly, we look at net asset value, and we think our stock is a really prudent buy. And then as far as our overall leverage, I don’t think anybody is going to accuse Coterra being over levered. You’ve heard me say before, I’ll never lose a minute of the sleep worrying about how low our debt is. I know that somehow violates financial theory. I just have good balance sheet management. But when you live in a cyclic commodity business, you find that people that read those business school textbooks on financial theory into the filing on the way with their bankruptcy papers. And we’re going to manage Coterra for the long run.

Arun Jayaram: Yes, but it’s a sleep bull at night balance sheet. My follow-up is just maybe for Blake is your Marcellus well costs are guided down to $950 a foot in the second half versus $1,200 a foot in the first half. Talk to us about the decline? And what’s the good go-forward run rate?

Blake Sirgo: The decline is really just driven by the well set that we’re bringing on that part of the year. We have some great, really long laterals that are in there and they trend on a lower dollar per foot. Run rate is kind of hard to pin down exactly one into 10, it depends if you’re talking up for Marcellus, Lower Marcellus. I think it could be anywhere from $1,000 to $1,200 per foot. It’s probably going to flow in there. Lateral lengths could drive that a little lower.

Arun Jayaram: Great. Thanks a lot.

Operator: We’ll move next to Neil Mehta at Goldman Sachs.

Neil Mehta: Yes, good morning, Tom and team. Really great quarter. The first question I had was just — we’ve seen so much consolidation across the landscape, the energy landscape. And certainly, you guys did your large deal a couple of years ago, but I just love your perspective on the role of Coterra and future consolidation and where do you see bid and ask, do you see any gaps in the portfolio?

Thomas Jorden: Yes. I’ll see that up and let Shane comment. We’re — the fact that we haven’t announced the transaction. As you’ve heard me say before, shouldn’t be misinterpreted that were not active in the space. We’re evaluating a lot of assets. We’re looking at how they may fit into our portfolio and really evaluating them against what we think the market demands for those assets. And I’ll just slide out, say, as we’ve recently reviewed the landscape of deals, there’s probably only one or two that we say, “Oh, we might have liked to have had that. But those were small bolt-ons. I think we feel pretty good about as we review the decisions we made on that. But we look at everything. And we have a lot of confidence in our operations team and would love to find more assets for them to say gray/silver.

And we’re going to remain curious and active on that. But I just don’t want it to be misinterpreted that we’re sleeping on the sidelines. We are actively engaged and have made tactical decisions to hold firm. Shane, do you want to comment on that?

Shane Young: Yes. I’ll just add on a couple of things. I wholeheartedly agree. The team has been executing incredibly well, and we’d love nothing more than to have an opportunity to put more assets and opportunity under their stewardship. And we think it helps in terms of execution in the field. We think it also plays into our strengths of capital allocation. I think the bar has been and remains very high. And — but I think if we were to find something that had the right strategic fit, the right valuation parameters and less the balance sheet in good shape, that would be something we’d be highly interested in.

Neil Mehta: And the follow-up also on M&A. You have been commodity agnostic. It seems to us and focus more on where you can generate the highest return. Is that the way you think about M&A as well? You’re less focused on the product type and more focused on what’s the best fit just perspective on Oil versus Gas and consolidation?

Thomas Jorden: Yes. I think our first lens is always financial on everything we do. Now all else being equal, things are never equal. And you get structural changes in the markets, both for oil and natural gas. I would say all else being equal, we’d probably add a little more oil to our portfolio. But check back with me six months from now on that. I mean we really have a history of feedback that if we focus on sound financials, we focus on asset quality if we focus on the amount of windage we have between our price file and our cost of supply, that’s the right focus. And whether it’s gas, oil or NGLs. I would say in our DNA, we have a fundamental indifference to that. But not to say we’re not also interested in a balance. I mean completely, we want to balance some of our revenue mix.

Neil Mehta: Thanks.

Operator: We’ll go next to Betty Jiang at Barclays.

Betty Jiang: Good morning. I want to ask about the three-year outlook. You have beaten 2024, and that’s flowing into better 2025 and ’26 numbers, which is great to see. With all the efficiency gains that you’re talking about, is it fair to think that they would just continue to translate into a better outlook over the entire three-year period and that you will just be delivering that five plus type of growth for maybe seeing to lower CapEx?

Thomas Jorden: Yes, I’ll hit it up and I want Blake to comment. I think sometimes people give us credit for being better modelers than we are. We really do try to come out with outlooks that are aggressive and what we think we can achieve. We do not model in future cost reductions or future efficiencies unless we have line of sight to them. And that’s kind of — I have to kind of apologize for that because we are an innovative organization. We wake up every morning and we say, we’ve been highly successful and we’re worried sick over because we never want success to get in our way of progress. You’ve heard us talk about progress versus comfort. So I’ll tell you with great humility that when we laid out our three-year plan in February, we were going to say 5% oil growth, and we had a debate internally as to whether we say five-plus.

And that plus was hotly debated. And we said, “No, let’s put the plus sign in because we might beat that. And here in the last two years, we’ve added 10% oil growth. It’s not that we’re sandbagging our model. It’s that our organization is really innovative. But we can’t — we’d rather talk about results, then promise things that we can’t solidly look in the eye and say, we will deliver it. So in some sense, it’s a cultural issue. We’re results for a company. And if we end up under promising, we’d rather have that than overpromising.

Shane Young: Yes, Betty, I would just say, as I said in my earlier remarks, we still have strong conviction in the outlook that we put out in February. So 5% plus oil growth, 0% to 5% BOE and gas growth, all at $1.75 billion to $1.95 billion of annual capital. I think the results that we have delivered in the first quarter only give us further conviction around that outlook. So we’re still excited about it. And believe we’ll be able to deliver it.

Thomas Jorden: Blake, do you want to say anything about the future position?

Blake Sirgo: I would just echo what Tom said. We don’t bake in any efficiency gains in our three-year outlook. What we’re doing today is what we show. But as Tom said, the expectation here is that we get better every single year. We have a culture of operational excellence. That means what we did yesterday, will not cut it for today. And our teams are constantly looking for ways to drive our cost structure and efficiencies are expected. Now there’s lots of other things that affect costs, what’s the market going to do? How many rigs are running, how many crews are running? There’s lots of things around our cost structure, we don’t control. So — we don’t bake in anything. We don’t bake in inflation, we don’t bake it in deflation. We don’t bake in further efficiency gains. When we put out a guide, it’s the way we see the world today.

Betty Jiang: That’s great. And it definitely can see the operational momentum across the board, and that’s not an issue at all from a culture perspective. On a — my follow-up, I want to ask about the Harkey. I think in your slide deck, you mentioned that you will go back to the Harkey on the Windham Row in Phase 2 within the next 12 months. Just wondering, is there any incremental savings that you can extract from that second phase Harkey, both from shares facilities or anything along that line that you can extract on the cost side? And then secondarily, Tom, you mentioned that you saw some benefit from coal development. So what does that — what could that mean for the Harkey — Harkey road development? Thanks.

Blake Sirgo: Yes. This is Blake. I’ll take that one. The — there are cost efficiencies when we come back. The biggest ones our pads are built, our facilities are built. This is why, historically, we like if we can develop benches separately, you can let a bench decline in volume come right back in at another bench for very little incremental cost. So we will enjoy some of those cost savings when we come back from the Harkey possible co-developed benefits, that’s really what we’re interested in learning about. We’ve just seen some results lately that says the performance of the Harkey is better when we co-develop with the Upper Wolfcamp versus overfill. And we’re interested in learning more about that. But as Tom said, until we do, we’re leaning in. We’re going where the data takes us, and we’ll see what these next round of codeveloped wells tell us.

Betty Jiang: Great, thank you.

Operator: We’ll move next to David Deckelbaum with TD Cowen.

David Deckelbaum: Good morning, Tom and team. Thanks for taking my questions. I wanted to ask maybe a little bit of just a cost benefit analysis. You guys have been beating production now steadily largely on what appears to be cycle times and just finding ways to do things faster in the field, which is quite commendable. I think you guys articulated the benefits of cost savings on things like the Windham Row in the 10% range. As you get better with some of the smaller projects, how do you think about that balance versus larger project savings? Or should we think that even with some of the faster accomplishments that you’ve achieved with smaller developments that you would be able to exponentially improve upon that as you get to larger developments?

Blake Sirgo: Yes, David, this is Blake. I’ll take that one. I think it’s important to iterate cost is an output of our decision-making. And so while lower cost really helped drive some of our economics, we are focused on total returns of our projects and the highest PVI. And so, if that ends up being a three-well project in Lea County versus a 54-well project in Culberson County, we go where the PVIs tell us to go. And Obviously, continued cost gains really help. Cycle times really help, but it doesn’t drive where the rigs go. It really drives us that full economic analysis, and that’s what we lean into.

Thomas Jorden: An example of that, I love what Blake said, the cost isn’t a first order driver. For now and again, we’ll have a project either underway or soon to be underway. And our teams through additional science analysis, we’ll propose spending more on completions on a project and drives the cost up. But we always look at the incremental benefit financially and make the best decision we can. We learned — we all learned early on that you can’t save yourself rich. You have to create value.

David Deckelbaum: I appreciate the color on that. Maybe just pivoting to the Marcellus, a similar line of questioning on just how you thought through deferring completion activity versus curtailing existing production and keeping up with the completion kins, if there is sort of the inefficiency of drilling programs and frac crews that gets lost in that process or how you guys approach that sort of thought train?

Blake Sirgo: Sure. This is Blake. I’ll take that one. Yes, it absolutely is a trade-off, you’re spot on. Our preference is to run a frac crew continuously. We know that’s when we get our best efficiencies. But once again, it’s back to that investment case and what are the economics of the project. And while that might give us better efficiencies, given where gas prices are, we just can’t have that level of investment in the Marcellus right now. We need to slow down. We need to throttle down. And so that does mean usually giving up a little bit of efficiency but that’s still the prudent capital decision to make, and that’s why we’re doing it.

Thomas Jorden: I want to give a little different spin on an answer here, David. The Marcellus is a great operating area, and we are very constructive on natural gas prices. But I’m also going to tell you that, as you know, we’ve reentered a part of the field that hasn’t seen drilling over time. And we’re very pleased to be doing that. And this just gets to my being a responsible operator and communities we operate. Susquehanna County, 20 years ago was one of the Forest Counties in Pennsylvania. And because of the resource development there, that county is thriving. And there’s a whole group of landowners that have participated in that because been ahead of an area we are precluded from drilling it. And so we want to be really thoughtful before we just defer completions there. And we’re going to continue to have an ongoing activity and not that we’re going to be financially reckless because we won’t. But our impact on the community is part of our decision-making.

David Deckelbaum: Thanks, Tom. Thanks, Blake.

Operator: We’ll go to our next question from Scott Gruber at Citigroup.

Scott Gruber: Yes, good morning. Tom, long-dated gas because they have been moving higher on all the data center growth excitement, how would you think about capital allocation between Anadarko and the Marcellus, if the forward curve is right, and we’re in the $3.50 to $4 range, in late ’25, ’26? And oil is still healthy, call it, in the 70s. How would you think about that allocation?

Thomas Jorden: Well, I wouldn’t have to thank very hard. I’d look at the incremental economics and we go where the best economics are. We have tremendous gas resources in both basins. The — and Anadarko has natural gas liquids, which really provides an economic boost. But the Marcellus has amazingly low cost of supply, and we produce pure methane, which we just have to compress and put into an air state line, so — or a pipeline. And so we would look at the economics. I think if we were — if some of the promise comes through on the increased need for natural gas and electricity generation, you probably see us increase activity in both basins and also seek creative long-term contracts that might give us exposure to electricity pricing. Blake, you want to comment on that?

Blake Sirgo: Yes, sure. I mean we’re all learning this AI power demand story together, and there’s a lot of unknowns, but there’s a lot of excitement the power gen that’s going to be required is huge. Lots of it looks like it’s going to come on the East Coast. That’s very proximal to our asset. There’s a lot of existing pipes there that we can easily get our gas to those markets. And we’re very interested. We’re talking to a lot of these folks directly trying to understand their business and their needs, and we will be ready to participate.

Scott Gruber: It’s exciting. We’ll wait for a word. And then just turning back to Windham Row. Just curious, you mentioned doing simul-frac on half the wells. What’s the limitation there, why not doing on all the wells? Is it comfort with the technique or tag configuration or scheduling the frac crews? Just some color on the limitation there? And if there’s any upside to doing it on more than half?

Blake Sirgo: Yes, Scott, it’s Blake. I’ll take that. That’s a great question. And I think it’s something that gets missed sometimes in simul-frac is you really have to have an optimal pad with a lot of wellheads on one pad to optimize the cost savings. There is sometimes where you might some frac and save no money because a simul frac crew is just basically two frac crews smashed together. So you’re paying a lot of money for that crew to be there. The efficiencies come when you have a lot of wells on one pad. And just the layout of these drill spacing units doesn’t always give us enough wells per pad to use some frac optimally. So it’s back to that whole cycle analysis. The goal is not to simul-frac everything. The goal is to make the most economic wells. And so we’re only chasing it where it makes sense.

Scott Gruber: Well, I appreciate the color. Thank you.

Operator: Our next question comes from Neal Dingmann at Truist.

Neal Dingmann: Good morning, Tom. Thanks for the time. My first question comes for you or Blake, maybe on inventory, specifically. Looking at Slide 5, you had an interesting comment that I think makes a lot of sense, and that’s you all suggest that the total fluctuates based on things like well spacing cost, cadence and the like. And I’m just wondering how aggressive or conservative would you consider your estimates versus what you’ve seen play out in the trends in recent quarters?

Thomas Jorden: Well, I’ll just say, we have future landing zones that are not modeled in that inventory. But we want to be very careful with how we talk about inventory. And when I say that, I mean, we want to deliver what we promise. And so we don’t throw the kitchen sink in, although our inventory today has zones that we didn’t have in our inventory a few years ago. There are still zones to be tested, both shallow and deep. And we’re pretty optimistic about our ability to extract maximum value out of an acre of land. But the inventory we published is one that we think we can deliver.

Neal Dingmann: Very good. And then just a second question on capital spend. Specifically, I noticed what I think now what is about 70% of CapEx is directly from Upper Marcellus. Is this a result of just productivity that you highlight on Slide 19 or what’s driving the spend in this upper area?

Blake Sirgo: Well, we have some great upper locations in the field. Our Tier 1 uppers really long lateral lengths, competitive economics. And so they’re just competing for capital. But also the upper is the future of the assets. So we’re — we like having activity in the upper. We’re still learning about it. We’re still trying to understand our well spacing and our frac design. And it’s important, we continue projects in that zone.

Neal Dingmann: Thanks, Blake. Thanks, Tom.

Operator: We’ll go next to Derrick Whitfield at Stifel.

Derrick Whitfield: Good morning. Thanks for your time.

Thomas Jorden: Good morning, Derrick.

Derrick Whitfield: Tom or Shane, a bit of a build on an earlier question. If gas prices were to continue to underperform throughout 2024. How would you weigh or evaluate the decision between reallocation of CapEx and increased return of capital? I suspect your Anadarko and Permian teams would like more capital.

Thomas Jorden: Yes. You’re saying the Marcellus pricing stays kind of in and around where it is like this through the rest of the year?

Derrick Whitfield: That is correct.

Thomas Jorden: Yes. Well, look, here’s what I’d say is we do build in a lot of flexibility into our capital planning. And a couple of that’s really foundational to that and a couple of things. One, some plans to accelerate if market environment changes and things get better and also to decelerate if they deteriorate or, in this case, don’t firm up a little bit. I think the second element is we don’t engage in a lot of long-term contracting. And that’s really what gives us the flexibility to make those adjustments as we go. And I would say we maintain that flexibility as we get to the end of this year and into next year, if that’s what the market signals say, and that’s what translates through into the economics. We certainly have a great set of inventory that we just talked about throughout the portfolio that would have a call on, on capital if prices remain like this for an extended period of time.

Derrick Whitfield: As my follow-up, regarding the deferred training lines in the Marcellus. How long would you technically be comfortable in deferring the wells before you’d be concerned with compromising the effectiveness or integrity of the completion?

Thomas Jorden: Yes, we’ve looked at that long and hard and we don’t see a degradation in shut-in time. There’s a history as you go back a decade of fairly significant shut-ins. We don’t really have a time clock attached to it. But I — we’re anticipating turning these wells online later in the year. And we’re — our data tells us that those reservoirs will not suffer because of it. And part of that is because we don’t produce much water there. And so you don’t really have the issues that you might have in the other basins.

Derrick Whitfield: That makes sense. Thanks for your time.

Operator: We’ll go next to Leo Mariani at ROTH MKM.

Leo Mariani: I wanted to just dive in a little bit more to CapEx here. I wanted to kind of get a sense on sort of how the numbers are trending. See second quarter CapEx is going higher, do you expect CapEx to kind of come down a little bit in the second half versus the first half, is kind of second quarter, potentially the peak here and — when you talk about flexibility in the program, I know you mentioned a couple of times, potentially room for more activity. Is that more just kind of a function of some of the savings you’ve seen year-to-date?

Shane Young: Yes, Leo, thanks for the question. And look, there’s a couple of things I would just point to, one, Hana put together a great slide, a new slide in the deck, in the Appendix 33 that sort of shows where some of the activity is over the course of the year. And your point that you just made around, does it feel like the second quarter could be a peak capital quarter and then the back half of the year, if you take the residual and divide by two, that may be a lower number than that. And that sort of bears itself out, I think, on this page. So I don’t — yes, I think you’re interpreting the data the right way in terms of what the pace could look like for 2024.

Leo Mariani: Okay. I appreciate that. Then I just wanted to follow-up a little bit on kind of Upper Marcellus. As you look out the next couple of years, do you see the Upper Marcellus becoming kind of increasing percentage of your overall Marcellus activity. Is that going to be just kind of driven by somewhat the depletion of the Lower Marcellus in the inventory stack here?

Blake Sirgo: Yes, Leo, you nailed it. It’s — the Lower Marcellus has been a wonderful zone, and we know all the remaining sticks, and we plan on drilling them here in the next few years. And the remaining is all the Upper. That’s the future of the asset. And so as we are chewing through our lower inventory, you’ll see more upper come in each year. We’re really focused on testing and delineating the upper and just proving it out. But yes, depending on capital spend, the Upper will be a bigger and bigger portion of our program.

Leo Mariani: Okay. No, that’s helpful. But it sounds like the message is you think the Upper can be very, very competitive with other gas assets as you look at it today?

Blake Sirgo: Yes. I mean there’s parts of the field that are super competitive, but I’ll just caveat the Lower Marcellus in this asset is some of the absolute best rock in all of the Lower 48. And I don’t think it’s going to compete with the cream with a crop lower that’s been drilled. But there’s — it’s still very competitive in our capital allocation.

Thomas Jorden: Yes. And Leo, competitiveness is always a function of well performance, but also price. And that’s a nice thing about Coterra where we said is we really do have an asset mix allows us to shift capital and allocate it based on those changes. So competitiveness of assets is not a static thing.

Leo Mariani: Okay, I appreciate it. Thank you.

Operator: Next, we’ll go to Charles Meade at Johnson Rice.

Charles Meade: Good morning, Tom to you and team. Just one question for me, and it’s around the way you guys are going to approach the Marcellus in the back half of the year. I think you — I heard you mentioned in your prepared comments that your plan has you guys turning some wells on in July. And as I think about recent history up in the Marcellus, a lot of times, we can see a good price bounce in the summer, but then we see another about a weakness in the Fall when the cooling demand goes away. So is there a scenario where you guys bring some wells on in July and then curtail them or kind of you shut them in again in the Fall? Or is it more along the lines of once you guys decide to bring them on? You’re just going to — you’re going to — you’re going to keep them on and does that bias you to turn them on later?

Thomas Jorden: Yes. I’ll just — I’ll answer your question with the analogy. We’ve said from day 1 that the way we manage our program is not a rifle shot, it’s a guided missile. So sitting here and saying we’re going to turn wells on in July, that’s talking about a rifle shot. We’re going to guide that missile every step of the way. We typically don’t manage our production up and down with the near-term price file. It usually takes something structural for us to make production decisions around price. And that’s the luxury of having low-cost supply, by the way. Right now, we have a structural issue with low gas prices, which is why we’ve turned those in line. And I’ll just say that July is what we’re carrying in our current model, and we’re going to make the best business decision and model will be down.

So I want to make sure of that. But I don’t think you’d see us ramp our production up and down with a changing price file. We just like to get north of a place where with the low-cost supply, we don’t have to worry about it.

Charles Meade: Got it, that’s helpful. Thank you.

Operator: And that concludes our Q&A session. I will now turn the conference back over to Tom Jorden for closing remarks.

Thomas Jorden: Yes. I just want to thank everybody. Great set of questions. We are very pleased to present the results we presented last night and look forward to repeating that. And as I said many times on this call, it’s our — talking about results is the conversation we want to have. So thank you all very much for your participation this morning.

Operator: And this concludes today’s conference call. Again, thank you for your participation. You may now disconnect.