Good morning. My name is Audra, and I will be your conference operator today. I would like to welcome everyone to the Coterra Energy Inc.'s First Quarter 2024 Earnings Conference Call. Today's conference is being recorded. I will now turn the conference over to Dan Guffey, Vice President of Finance, Investor Relations and Treasurer. Please go ahead.

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 that were provided in our earnings release and updated investor presentation, both of which can be found on our website. With that, I'll turn the call over to Tom.

Thank you, Dan, and welcome to all of you who 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 102,500 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 in 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 2 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 forecasts 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.

Thank you, Tom, and thank you, everyone, for joining us on today's call. This morning, I'll focus on 3 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 turned in-line 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. 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 2 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-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 $575 million in 2024 notes at maturity during the third quarter. Until the maturity, we have invested the proceeds in 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 $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 3-year outlook we provided in February. With that, I will hand the call over to Blake to provide details on our operations. Blake?

Thanks, Shane. This morning, I will discuss our capital expenditures and provide an operational update. First quarter accrued 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 102,500 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 2 Permian crews and 1 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 2 frac crews and 8 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 drive 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 dollar 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 3 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 3 new co-developed 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 3 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 1 rig and 1 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 that come into play at lower NYMEX pricing. We currently have 2 pads consisting of 12 wells in total that we are delaying turn-in-lines. Each incremental molecule we bring on receives in-basin pricing 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 wellhead 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 2 rigs and 1 frac crew. We are in the middle of a large block of completion activity, with 3 projects being fracked over the first half of 2024. These projects are focused on liquids-rich portions of our asset, which maintain 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 increase 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 remain 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.

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 than future promises, and we're always pleased to deliver them. With that, we'll turn it over to questions.

We'll take our first question from Nitin Kumar at Mizuho.

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 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?

Thank you, Nitin. First, I want to mention that if there is a specific price or complex formula, I haven't received that information yet. However, we are monitoring our received price. We typically reference Leidy when discussing our selling points, and when the price falls below $1.50, we reassess our outlook. We also have considerations for transportation and LOE costs. While I can't pinpoint a specific price, we do maintain a very low cost of supply and would prefer our netback to be above $1. We are currently making decisions on a month-to-month basis. Our existing model suggests we will bring additional wells online in July, but our optimism is tempered by the situation on the ground. There are two factors to consider regarding price: one for when we bring wells online and another for when we may increase our investments. Our capital program can accommodate an increase, and if we proceed, we anticipate a significant rebound in our volumes in 2025 and 2026, which presents a different pricing scenario. We remain positive about natural gas, but the current environment is challenging. We believe that moderating our turn-in-lines is advisable. We will also observe the market actions of other players, as there is a significant amount of gas and many companies engaged in similar activities. When we do bring wells online, we will carefully evaluate market conditions, particularly if there’s a sudden influx of gas that could influence our decisions.

Great. 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 you have seen? Obviously, adding a few wells in the Harkey 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?

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 1 layer at a time or not, 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 2, that co-developing the Harkey and 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 as probably our default option. As we continue to learn, and we're not chiseling and granting final conclusions here.

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.

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?

Yes, I'll let Shane handle that one.

I appreciate the question. We consider a variety of factors when making decisions regarding our return program and its pace. Valuation is a major consideration for us, and we find our stock to be attractively valued, which encourages us to take further action. Additionally, we assess liquidity, noting that we are above our target level as of the end of the first quarter. Free cash flow during any given period is also important, among other considerations. Toward the end of last year, we discussed options for handling the 2024 maturity and explored various scenarios. With good cash reserves and liquidity, one option was to pay in cash. As we entered this year, the market emerged favorably for new debt issuances, which influenced our decision. Consequently, we will repay $575 million of debt later this year, primarily using proceeds from a $500 million new issuance and some cash reserves. This clarified the potential impact of that maturity on our liquidity. As that became clearer, coupled with free cash flow and our attractive stock price, we decided to proceed with our share buyback program in the first quarter.

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

We've gone as low as $600 million over the last, call it, 7, 8 quarters. And again, I think that probably as low as we 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.

So, 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 anyone is going to accuse Coterra of being over-levered. You've heard me say before, I'll never lose a minute of 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 end up filing for bankruptcy. And we're going to manage Coterra for the long run.

Yes, it's a sleep-well-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 that decline? And what's the good go-forward run rate?

The decline is really just driven by the well set that we're bringing on in 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, it depends if you're talking upper Marcellus lower Marcellus. I think it could be anywhere from $1,000 to $1,200 per foot. It's probably going to fall in there.

Tom, great quarter. My first question is about the significant consolidation we’ve observed in the energy sector. You completed a major deal a couple of years ago, so I would appreciate your insights on the role of Coterra in future consolidations, along with your thoughts on pricing disparities and any potential gaps in your portfolio.

Yes. I’ll see that let Shane comment. The fact that we haven't announced the transaction. As you've heard me say before, shouldn't be misinterpreted that we're 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 1 or 2 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 optimize. 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 both firm.

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 left the balance sheet in good shape, that would be something we'd be highly interested in.

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?

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 6 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 our revenue mix.

I want to ask about the 3-year outlook. You have beaten 2024, and that's flowing into a 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 3-year period and that you will just be delivering that 5-plus type of growth for maybe seeing to lower CapEx?

Yes, I will address this and I want Blake to provide his thoughts. Sometimes, I think people assume we're better at modeling than we actually are. We strive to present outlooks that are ambitious and reflective of our capabilities. We do not account for future cost reductions or efficiencies unless we have clear visibility into them. I apologize for that because we are an innovative company. Each day, we aim for continued success but are not satisfied, as we never want success to hinder our progress. We've discussed progress versus comfort before. With that in mind, I want to humbly mention that when we outlined our 3-year plan in February, we anticipated 0-5% oil growth and debated internally whether to state 5% or higher. Ultimately, we decided to include the plus sign because we believed we could exceed that. Over the past two years, we've achieved a 10% oil growth. This isn't because we're being overly cautious; our organization is genuinely innovative. However, we prefer to discuss results rather than make promises that we cannot confidently commit to. It reflects a cultural aspect of our company. If we end up setting lower expectations, we prefer that over making inflated promises.

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 gives us further conviction around that outlook. So we're still excited about it and believe we'll be able to deliver it.

I would just echo what Tom said. We don't bake in any efficiency gains in our 3-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 factors 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 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.

That's great. I definitely see the operational momentum across the board, and that's not a concern from a culture perspective. For my follow-up, I want to ask about the Harkey. In your slide deck, you mentioned that you will revisit the Harkey on the Windham Row in Phase 2 within the next 12 months. I'm curious if there are any additional savings you expect from that second phase of the Harkey, whether from shared facilities or other cost-related factors. Additionally, Tom, you noted that you’ve seen some benefits from co-development. What could that imply for the Harkey pad and Harkey road development?

Yes. This is Blake. I'll take that one. There are cost efficiencies when we come back. The biggest ones are 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 suggest the performance of the Harkey is better when we co-develop with the Upper Wolfcamp versus over-fill. 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 will see what these next round of co-developed wells tell us.

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?

Yes, David, this is Blake. I'll take that one. I think it's important to iterate that cost is an output of our decision-making. And so while lower costs really helped drive some of our economics, we are focused on total returns of our projects and the highest PVI. So, if that ends up being a 3-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 to that full economic analysis, and that's what we lean into.

I appreciate what Blake mentioned about cost not being the most crucial factor. Currently, we have projects either in progress or about to start. Our teams will analyze the situation scientifically and might suggest increasing spending on project completions, which could raise costs. However, we always evaluate the financial benefits and strive to make the best possible decisions. We've all learned that you cannot become wealthy solely by cutting costs; value creation is essential.

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, considering 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.

I want to approach this question from a different angle, David. The Marcellus is an excellent operational area, and we are optimistic about natural gas prices. However, as you know, we have reentered a section of the field that hasn't been drilled in a while, and we are excited about that. This reflects our commitment to being responsible operators and to the communities we serve. Twenty years ago, Susquehanna County was one of the leading counties in Pennsylvania, and it is thriving today due to resource development. Many landowners have benefited from this, especially since we have refrained from drilling in certain areas. Therefore, we want to be careful about delaying completions there. We will continue to engage in ongoing activities, but we will not act irresponsibly with our finances. Our impact on the community is a crucial factor in our decision-making.

Tom, long-dated gas has 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?

I wouldn't have to think very hard. I would consider the incremental economics and choose the areas with the best economics. We have significant gas resources in both basins. Anadarko has natural gas liquids, which provide an economic advantage. However, the Marcellus offers remarkably low supply costs, and we primarily produce pure methane, which simply needs to be compressed and sent into a pipeline. Therefore, we would evaluate the economics. If there is a significant increase in demand for natural gas and electricity generation, we may increase our activity in both basins and look for innovative long-term contracts that could expose us to electricity pricing.

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.

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?

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 are times where you might some frac and save no money because a simul-frac crew is just basically 2 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 simul-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.

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?

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.

Very good. And then just a second question on capital spend. Specifically, I noticed what I think now 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 the upper area?

We have excellent upper locations in the field. Our Tier 1 uppers have very long lateral lengths and competitive economics, which makes them attractive for investment. Additionally, the upper area is key to our assets' future. We appreciate having activity there and are still in the process of learning about well spacing and frac design. It's essential for us to continue projects in that zone.

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 reallocating CapEx and increased return of capital? I suspect your Anadarko and Permian teams would like more capital.

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

That is correct.

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 capital if prices remain like this for an extended period.

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

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 we're anticipating turning these wells online later in the year. And 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.

I wanted to discuss Capital Expenditures in more detail. I'm interested in understanding the trends in the numbers. It appears that Capital Expenditures in the second quarter are increasing. Do you anticipate these expenditures will decline somewhat in the second half compared to the first half? Is the second quarter possibly the peak? When you mention flexibility in the program, you have indicated there could be more room for additional activity. Is this mainly due to some of the savings you have achieved so far this year?

Thank you for your question, Leo. I want to highlight a few points. Hana created a great new slide in appendix 33 that illustrates the activity throughout the year. Regarding your observation about the second quarter potentially being a peak for capital expenditures, and considering the remainder of the year, if you take the residual and divide it by two, it could indeed result in a lower figure. This aligns with what is presented on that page. I believe you are interpreting the data correctly regarding the pace we can expect for 2024.

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 an 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?

Yes, Leo, you nailed it. 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.

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?

Yes. There are areas in the field that are highly competitive, but I want to point out that the Lower Marcellus in this asset contains some of the best rock in the Lower 48. I don't believe it will compete with the top tier regions that have already been drilled. However, it remains quite competitive in our capital allocation.

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 that allows us to shift capital and allocate it based on those changes. So competitiveness of assets is not a static thing.

I have one question regarding your strategy for the Marcellus in the latter half of the year. I recall you mentioning in your prepared remarks that you plan to start some wells in July. Looking at recent trends in the Marcellus, we've often seen a price improvement in the summer, followed by a decline in the fall as cooling demand decreases. Is there a chance you might initiate production in July and then later reduce or stop it in the fall? Or once you begin operation, do you intend to keep the wells running, which might influence your decision to start them later?

Yes. I'll respond to your question with an analogy. From the beginning, we have stated that our program management resembles a guided missile rather than a rifle shot. Simply saying that we will activate wells in July is akin to a rifle shot. We intend to guide our approach meticulously throughout the process. Generally, we do not adjust our production in response to short-term price fluctuations; it typically requires significant structural changes for us to make price-related production decisions. This is one of the advantages of having low-cost supply. Currently, we are facing a structural issue with low gas prices, which is why we are bringing those wells online. I want to clarify that July is what we are projecting in our current model, and we'll make decisions based on sound business principles while being prepared for potential adjustments. However, we are unlikely to fluctuate our production significantly in response to changing prices. Our goal is to reach a production level where, thanks to low-cost supply, we don’t have to be overly concerned about price changes.

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

Thank you, everyone. Those were great questions. We are very happy to share the results we announced last night and look forward to doing it again. As I have mentioned several times on this call, discussing our results is the conversation we want to have. Thank you all for participating this morning.

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