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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: Hello and thank you for standing by. My name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Coterra Energy Fourth Quarter 2023 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question-and-answer session. [Operator Instructions] I would now like to turn the conference over to Dan Guffey, Vice President, Finance, Planning and Investor Relations. Please go ahead.

Dan Guffey: Thank you, Operator. Good morning. And thank you for joining Coterra Energy’s fourth quarter and full year 2023 earnings and 2024 outlook 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 reconciliation for the most directly comparable GAAP financial measures, were provided in our earnings release and updated investor presentation, both of which can be found on our website. With that, I’ll turn the call over to Tom.

Tom Jorden: Thank you, Dan, and welcome to all of you who are joining us on the call. Coterra had an excellent fourth quarter, as shown by the results that we released last night. Shane will walk you through the specifics here, which include coming in above the high end of our guidance on oil, natural gas and Boe or barrels of oil equivalent, and below our capital guide. For full year 2023, we finished the year with 5% year-over-year growth in Boe and 10% year-over-year growth in oil volumes, while hitting the midpoint of our capital guide. More importantly, we generated excellent returns. We also made great progress on emissions reduction and continue to push the envelope on our environmental initiatives. As we look ahead to 2024, total capital is projected to be between $1.75 billion and $1.95 billion.

Given the outlook for commodity prices and commensurate revenue, we think that this is a prudent level of investment, as it invests approximately 60% of our projected cash flow. We will grow our investments in the Permian and the Anadarko Basins and retrench in the Marcellus. We are reducing our Marcellus investments by over $400 million in 2024 compared to 2023. Mark Twain said that, a man learns something by carrying a cat by the tail that he can learn in no other way. Through the commodity cycles, we have learned that although downswings typically do not last long, they also do not come pre-labeled with how long they will last. We have learned to be disciplined and patient. Experience tells us that our focus should always be on returns and never on production or activity.

In this case, that means throttling back on our Marcellus program. We remain highly optimistic on the 12-month to 18-month outlook for the gas macro. The impact of new LNG export capacity coming online at the end of 2024 and early 2025 coupled with the possibility of cold weather provides reasonable hope for significant price recovery in natural gas. However, experience tells us that although we will underwrite our hopes with the future strip price, we should never underwrite our capital program with it. We will be patient and watch for recovery in the gas macro. Missing a few months of the recovery is much better than fully participating in the downside. We project that this slowdown in the Marcellus will result in our natural gas volume shrinking 6% in the Marcellus in 2024.

If we see signs of recovery in natural gas, our 2024 capital range includes a contingency plan to accelerate our Marcellus program in the latter half of the year, which would reposition us for significant growth in our gas volumes in 2025 and 2026. We will watch and be ready to act. In the meantime, we will pivot to our deep inventory in the Anadarko and Permian where our returns are excellent. We have a tremendous program ahead of us in 2024 and we are excited to be increasing activity in both the Permian and Anadarko. All three business units, however, are poised and ready for out-year acceleration should conditions warrant. This ability to redirect and reposition activity around premier assets is one of the differentiating strengths of Coterra.

We also provided an update on our three-year outlook. Our new 2024 to 2026 outlook has Coterra with an average annual CapEx of $1.75 billion to $1.95 billion, which is expected to generate annual growth in the low-single digits for Boe and 5% plus for oil growth. This plan leverages our deep, high-quality inventory, demonstrates improving capital efficiency and clearly displays the confidence we have in our ability to continue a cadence of operational excellence. This is an achievable outlook under current conditions. As always, we continuously adjust our plans with changing conditions. As we have previously said, planning at Coterra is a guided missile, not a rocket. In closing, I want to acknowledge our remarkable field organization. They set the pace for operational excellence.

They work in hostile environments with dedication, perseverance and an unwavering commitment to safety. They serve as an example to all of us. The Coterra brand stands for operational excellence, leading-edge technology and innovation, best-in-class development of outstanding assets, and the ability to adapt nimbly to changing market conditions. We want to be known for a pristine balance sheet, investment discipline and rigorous economic decision analysis. We are not perfect. However, having a great organization, great assets and a great balance sheet allows us to learn from our mistakes, make continuous progress and always push ourselves farther and harder. With that, I will 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 four areas. First, I’ll discuss highlights from our fourth quarter and full year 2023 results. Then, I’ll provide production and capital guidance for the first quarter and full year 2024. Next, I will provide a new and updated three-year production and capital outlook for 2024 through 2026. Finally, I’ll discuss our shareholder return program and our debt maturity later this year. Turning to our strong performance during the fourth quarter. Fourth quarter total production averaged 697 MBoe per day, with oil averaging 104.7 MBoe per day and natural gas averaging 2.97 Bcf per day. All production streams came in above the high end of guidance driven by well performance and acceleration of till timing during the quarter.

Specifically, turn-in lines during the quarter totaled 40 net wells, including 28 in the Permian, near the high end of guidance, and 12 in the Marcellus, slightly above the midpoint of guidance. During the fourth quarter, pre-hedge revenues were approximately $1.5 billion, of which 61% were generated by oil and NGL sales. In the quarter, we reported net income of $416 million or $0.55 per share and adjusted net income of $387 million or $0.52 per share. Total cash costs during the quarter, including LOE, workover, transportation, production taxes and G&A totaled $8.41 per Boe, near the midpoint of our annual guidance range of $7.30 per Boe to $9.40 per Boe. Cash hedge gains during the quarter totaled $46 million. Incurred capital expenditures in the fourth quarter totaled $457 million, just below the low end of our guidance range.

Discretionary cash flow was $881 million and free cash flow was $413 million, after cash capital expenditures of $468 million. For the full year 2023, Coterra produced outstanding results. Total equivalent production exceeded the high end of our initial February guidance, coming in at 667 MBoe per day. This outperformance was driven by a combination of better-than-expected well timing and beats unexpected well productivity. Oil production for the year was 96.2 MBoe per day, exceeding the high end of initial guidance by over 4%. Capital costs were right at the midpoint of our guidance range, coming in at $2.1 billion as a result of relentless focus on capital by our teams in each of our business units. Cash operating costs per unit totaled $8.37 per Boe for the year, slightly below our initial guidance midpoint.

Looking ahead to 2024. During the first quarter of 2024, we expect total production to average between 660 MBoe per day and 690 MBoe per day. Oil to be between 95 MBoe per day and 99 MBoe per day, and natural gas to be between 2.85 Bcf per day and 2.95 Bcf per day. We anticipate first quarter oil production to have the lowest average for any quarter during 2024, primarily as a result of tilt timing that pulled some volume forward and into the fourth quarter of 2023. Regarding investment, we expect incurred capital in the first quarter to be between $460 million and $540 million. For the full year 2024, we expect incurred capital to be between $1.75 billion and $1.95 billion, or 12% lower at the midpoint than our 2023 capital spend. Our 2024 program will modestly increase capital allocation to the liquids-rich Permian and Anadarko Basins, and significantly decrease capital by more than 50% in the Marcellus.

We expect total production for the year to average between 635 MBoe per day and 675 MBoe per day, and oil to be between 99 MBoe per day and 105 MBoe per day or 6% higher at the midpoint than oil was in 2023. Natural gas is expected to be between 2.65 Bcf per day and 2.8 Bcf per day, approximately 5.5% lower at the midpoint than gas production was in 2023. It is important to note that we have incorporated efficiency gains achieved in 2023 into our 2024 guidance. Reflecting on our new three-year outlook. As we did this time last year, yesterday we announced our new three-year outlook for 2024 through 2026. We believe this is a robust, capital-efficient plan that delivers consistent, profitable growth for our shareholders. We anticipate that our project inventory can deliver 5%-plus oil volume growth over this period, with zero percent to 5% Boe growth by investing between $1.75 billion and $1.95 billion of capital per year.

This reflects increased capital efficiency and is designed to afford Coterra the flexibility to reallocate capital between our business units as market conditions change. This outlook incorporates an appropriate level of reinvestment and delivers meaningful free cash flow to underpin shareholder returns. Moving on to shareholder returns. Last night, we announced a $0.21 per share base dividend for the fourth quarter, increasing our annual base dividend by 5% to $0.84 per share. This remains one of the highest yielding base dividends in the industry at well over 3%. Management and the Board remain committed to responsibly increasing the base dividend on an annual cadence. During 2023, despite relatively lower commodity prices and cash flow, Coterra continued to execute on its shareholder return program by repurchasing 17 million shares for $418 million at an average price of approximately $25 per share.

In total, we returned 77% of free cash flow during the year or just over $1 billion. We remain committed to our strategy of returning 50% or more of our annual free cash flow to shareholders through a combination of a healthy base dividend and our share repurchase program. On to our 2024 notes. We have continued to monitor and analyze opportunities regarding our $575 million maturity coming this September. With low leverage at 0.3 times, we believe we have strong access to the active refinancing markets. At the same time, we had approximately $2.5 billion of liquidity between cash and our undrawn credit facility at year-end, affording us many options with regard to our 2024 maturity. In summary, Coterra’s team delivered another quarter of high-quality results, both operationally and financially.

We are poised for a strong first quarter of 2024, which we believe will set a solid foundation for the full year 2024 and beyond. With that, I will hand the call over to Blake to provide additional color and detail on our operations. Blake?

Blake Sirgo: Thanks, Shane. This morning, I will discuss our capital expenditures and provide an operational update. Fourth quarter accrued capital expenditures totaled $457 million, coming in just below the low end of our guidance. The lower CapEx was driven by efficiency and cost gains, reduced infrastructure spend, lower-than-expected non-operated capital and shuffling of the timing on a few projects. As noted, strong execution in the field pulled a few Q1 tills into Q4, which contributed to the Q4 2023 production beat. Coterra finished the year at $2.104 billion of total CapEx, at our midpoint of our annual guide. This quarter marks the 10th quarter in Coterra’s existence and 10 straight quarters of delivering on our oil guidance.

This was accomplished thanks to our operations teams across our businesses, who strive for operational excellence. At Coterra, operational excellence means operating safely and with integrity, while always looking for ways to accomplish more or less. We do not tolerate sacred cows and we are always on the hunt for new ideas, even if they are not our own. As we enter 2024, we are delivering a plan that continues to do more for less. In the Permian, we are planning to turn in line 75 to 90 wells in 2024, which is down 13% over 2023. These wells will have a $1 per foot of $1,075, down approximately 10% year-over-year. In the Permian, we are currently running two frac crews and eight drilling rigs, which are performing at or near all-time efficiency records.

Our frac efficiencies are coupled with new contracts that offer increased cost savings to Coterra as we gain in efficiency. Across our Permian footprint, we are taking advantage of our large, continuous assets to bring economies of scale to bear. This is highlighted by our Windham Row project in Culberson County, where we are prosecuting a 51-well row development across six drill spacing unit, with each well targeting the Upper Wolfcamp. By concentrating activity at this scale, we are able to minimize rig and frac modes, co-mingle facilities and maximize simul. Combine this with our first grid-powered electric simul-frac, we expect to deliver these wells at 5% to 15% lower cost than our historical program. Our Permian asset is an engine of capital efficiency and that engine continues to find a new gear.

In the Marcellus, we are currently running two rigs and one frac crew, with plans to go to one rig and lower our frac activities. Our Marcellus ops teams worked diligently in 2023 to lower our cost structure through increased frac efficiencies, improved water handling and lower facility costs. We are also pushing new limits on lateral linkage, with 3-mile and 4-mile laterals now part of our program. These cost gains help us to minimize our D&C spend as we go into 2024 and throttle down our activities. Our 2024 Marcellus program remains flexible and includes multiple on-ramps and off-ramps, which will allow us to adjust to changing macro conditions if warranted. In the Anadarko, we are currently running two rigs and one frac crew. Our Anadarko team had a great year executing with improved drilling times and frac efficiency.

Our 2024 program includes 20 to 25 turn-in lines across five projects focused on our liquids-rich assets, which we expect will continue to yield strong returns. Consistency of execution paired with strong well results have made our Anadarko assets a stout competitor for capital allocation at Coterra. Our unrelenting focus on operational excellence continued to bear fruit in 2023 and we expect the team to seek out and execute incremental efficiencies in 2024. And with that, I’ll turn it back to Tom.

Tom Jorden: Thank you, Shane and Blake. We are pleased with our continued execution in 2023 and expect to deliver on our goals outlined in our 2024 plans. We appreciate your interest in Coterra and look forward to discussing our results and outlook. We’ll now be open for questions.

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Operator: [Operator Instructions] Our first question will come from the line of Nitin Kumar with Mizuho Securities. Please go ahead.

Nitin Kumar: Thanks. Good morning, Tom, Shane, and Blake. Thanks for taking my question. Congrats on a strong year that really showcases the idea that was behind Coterra. I guess I want to start at just the capital allocation. You’re cutting activity in the Marcellus in response to gas prices, but a lot of people think of the Anadarko Basin as a gas basin and you’re allocating some incremental capital there. Could you walk us through kind of the thought process there?

Tom Jorden: Thanks, Nitin. I’ll probably disappoint with my answer because it’s pretty simple. I’ll say up front, I know a lot of people think of the Anadarko in a lot of ways and I’d like them to keep thinking that way, because we think the Anadarko is a tremendous basin with great opportunity. One of the things that was a challenge for Anadarko team was just showing repeatability. I’ve talked at length about capital allocation being a function of return on capital and repeatability in addition to how much windage do you have in the price file and our team showed great repeatability on some outstanding projects in 2023. And so the increased allocation is really a function of letting them just continue their activity level.

Had we done anything other than that, we would have throttled back or pulled the plug on their continuing activity. The returns are outstanding. I’ll just say that. And so, we’re reallocating a little under $300 million between the Permian and Anadarko, and that’s just it was challenging because we have great returns everywhere. I’ll also say that one of the things that we see in the Anadarko coming forward is we have some peers that are also moving forward with increased activity and so we expect a larger outside operated call on our capital in the Anadarko. And some of that is embedded in that allocation. So really, it’s a problem that we’d love to have and we’re very pleased with our allocation decision.

Nitin Kumar: Great. Thanks for the color. And then, Tom, industry consolidation continues at a pretty frantic pace. As you look around the lease lines, you have new neighbors or maybe the same neighbor around you. Your thoughts on scale M&A for Coterra from here on out. You certainly have a plethora of organic opportunities, but I’d love to hear your thoughts on M&A going forward?

Tom Jorden: Hey, Nitin. Thank you for that. Our criteria is very simple. When we look at potential combinations, we ask ourselves, would we rather own a share of Coterra or a share of the combined reformulated company? And there are, of course, a lot of elements to that. But first and foremost, it must create value for our owners. And look, I think, The Wall Street Journal should have a weekend breaking story that says, Flash, everybody looking at everybody else in the M&P space, because that’s what we have. So there haven’t been any opportunities that we really have browbeat ourselves on that have come and gone. We remain deeply curious about what consolidation could offer for Coterra owners. But the bar is very, very high. I’ll just leave it at that.

Operator: Your next question will come from the line of Arun Jayaram with JPMorgan. Please go ahead.

Arun Jayaram: Yeah. Good morning, gentlemen. I was wondering, I’m looking at slide 15 in your deck where you’re highlighting your expectations for well productivity in the Delaware Basin relative to peers and the results from Coterra from 2021 to 2023. I was wondering if you could maybe provide some color around expectations on productivity in 2024, if we could kind of compare that to what you did last year.

Blake Sirgo: Yeah. Arun, this is Blake. I’ll take that. That’s really why we kind of give that range on that slide. As we’ve talked about in the past, our Permian program is really a rotation throughout our assets and that’s driven by a lot of different things. The mix can vary somewhat year-to-year, but over a multiyear timeframe, it’s pretty consistent. And so I just say we expect 2024 to fall well within that band to deliver another good year on productivity.

Arun Jayaram: And just thoughts on comparison to what you delivered in 2023. Just trying to understand how you think year-over-year productivity could trend on a per foot basis.

Blake Sirgo: I would say very similar. There’s definitely some room for upside there with some of the allocations, but I’d expect another strong year.

Operator: Your next question comes from the line of Doug Leggate with Bank of America. Please go ahead.

Unidentified Analyst: Hey. Good morning, guys. This is actually Kali [ph] for Doug. So thank you very much for taking my question. The first thing I want to hit is the Marcellus, where you’re adapting activity in response to price. Sorry, so I guess I’m trying to understand the scenario analysis. Is the Marcellus free cash flow break even on 24 strip? And assuming basis is static, at what hub price does activity begin to shift higher?

Tom Jorden: Kali, this is Tom. We’ve been debating that internally. I can’t give you a firm number, but I will say that, we look really carefully at receive price and I know we talk about weighted average sales price, but we really look at the price received by the next molecule, which is really a function of what would be a basis price, less are fixed costs. I would say we would really like to see a price close to or above $3, I think, before it would really meet a criteria that shifts a lot of capital. But it’s also a function of the oil-to-gas ratio. And we’d really like to see a sustained ratio that’s somewhere in the neighborhood of 20 to 1 oil-to-gas and we’re really optimistic we’re going to see that when the market recessed with LNG exports. But that’s kind of what we’re looking for.

Unidentified Analyst: I appreciate that, Tom. My follow up is on the Anadarko. I think to remember that the geology there being quite complex. So I’m wondering if you can expand on what the team accomplished last year to give you more confidence to re-engage in the capital program?

Tom Jorden: Well, geology is complex across our portfolio, and if you don’t have to catch myself or I’ll spend the rest of the call talking about geology. But what’s most important is that, we’ve tested this section, we’ve got a lot of calibration and we understand the stratigraphic variation, we understand the oil gas complex ratio variation, we understand the pressure and drilling challenges. So I think we’re highly calibrated. So, look, complex geology is a bigger issue at the early phases of development than when you’ve got that calibration and we feel really confident that we understand the geological overprint.

Operator: Your next question comes from the line of David Deckelbaum with TD Cowen. Please go ahead.

David Deckelbaum: Thanks for taking my questions, everyone. I was curious just if you could go into just, obviously, the program this year is shifting more or I guess it’s high grading a bit more into the lower Marcellus. I think in your multiyear outlook, you sort of assume that Marcellus production comes back up, I guess, about 100 million a day. And I guess it’s averaging in that 2.2 range versus 2.3 last year. Can you talk about the considerations of inventory management and how that mix of lower versus upper, is looking over time? It seems like there’s a multiyear shift now where you’re going to be emphasizing the lower a bit more in the lower price environment. But just wondering if there’s more nuance to it and if your thoughts have changed on the inventory management side there?

Tom Jorden: Our thoughts really haven’t changed. As we were — I would just repeat what we’ve said in the past. We’ve talked about a reduced inventory in the lower Marcellus. I think, if we were heavy on the lower Marcellus, we’d probably be talking about a three-year to five-year inventory at this point, three-year to six-year maybe, depending on our level of activity. Our inventory is longer than that now as we’ve lowered our investment. But it’s really a function of what’s available to us and that’s the function of our gathering system where we think we have additional capacity. But there’s also an area of this field that’s opened up to us that we’re out exploiting and we’re really glad to be there and getting after some of the really, really productive rock.

So, we’ll be drilling in the lower Marcellus for a long, long time. So when we quote inventory numbers, it’s really strongly overprint by which formation we’re drilling in. But the lower is going to be a significant part of our program for a number of years.

David Deckelbaum: Thanks to the color there. I’m also curious on the Permian, embedded in this multiyear 5%-plus oil growth outlook through 2026. How many sort of projects similar to the size of Windham Row are you baking in, I guess, per year? I know that there was an expectation that we would see sort of a large-scale project every year and a half. Is that still kind of the cadence for the multiyear guide or are there some early learnings from Windham Row that are kind of iterating that process now?

Blake Sirgo: Yeah, David. This is Blake. I’ll take that one. Right now we really expect to do a row project almost every single year. And I know that it’s kind of scary to talk about a 51-well development, but I think it’s important to remember these are six distinct drill spacing units that we have chosen to develop in a row to maximize efficiency. These units are our standard Culberson 2-mile Upper Wolfcamp units with designs from seven to 10 wells per section. This is just really our bread and butter. I mean, we’ve developed many of these over the years. We’re just stringing them together. Our ops teams work really hard to kind of war game these projects and these rows to think of all the execution risks that could go on.

That’s why we picked up our eighth rig sooner, to get a good duct build in front of the frac crew. These projects have large multi-well pads. That means if we have any well trouble, our frac crew can pivot while we deal with the well trouble. Our simul-frac part of this project, we’ve modeled really conservative completion timing and that’s because, it’s our first application of this in Culberson, but we don’t really expect our electric crew to operate any less efficient than it has in the past. We worked through a lot of sand and water logistics to make sure everything has abundant sourcing. We own and operate our SWD system out there. That means we have plenty of water on demand at all times. It allows us to keep it in the pipe, so we’re not building any produced water pits with this project.

This is just part of our operation now and I’d expect many more row developments for years to come.

Operator: Your next question comes from the line of Neal Dingmann with Truist. Please go ahead.

Neal Dingmann: Good morning, guys. Thanks for the time. My first question is just on the flat span and the zero percent to 5% Boe CAGR. I’m just wondering, did these assumptions include, I’m just wondering, do you assume with those on a go forward years, has that ensued well productivity, improved well productivity, lower well cost, or maybe just help me on what’s involved in those assumptions?

Tom Jorden: We don’t project future advancements in advance of having achieved them. I think we will achieve them, but we don’t — we like to calibrate results. I mean, hopefully that’s not a surprise to anybody on this call. We’d much rather talk about results than promises. And I just want to say one more time, we don’t manage our multiyear outlook by that production number. We look at projections of what we think is our assumed cash flow. We say how much of that cash flow do we want to invest and that’s typically in a fair way. I’m going to give a wide one of 40% to 70%, and that allows us to achieve our shareholder returns that we’ve promised. And then with that, we say, okay, here’s the capital, where’s the best place to put it and the very last part of that process is what production does it generate.

We don’t get over our skis on that. We try to push our teams to model the most recent operational efficiencies and then we drive them crazy trying to get better. But production is not the input, it’s the output of good, solid capital allocation.

Neal Dingmann: Great point, Tom. And maybe just a second along that same line, I’m just wondering, look at the slide that talks about the gas production. I’m just wondering, is it fair to say that, you maybe have seen peak production or is it just what you’re forecasting that are just a basis of what’s going on with prices and that’s going to be an ultimate driver?

Tom Jorden: Yeah. It would not be fair to assume anything from our projection other than it’s our current look at an uncertain future. We say that we have contingency plans. If gas prices really recover, as we hope they will, within our capital guide, we have plans to get back to work this year and set ourselves up for nice growth over the next two years. That’s not a plan, but it’s on the shelf ready to go.

Operator: Our next question will come from the line of Michael Scialla with Stephens. Please go ahead.

Michael Scialla: Hi. Good morning, everybody. I just wanted to ask about your return of capital. Obviously, way above your target for the year, but even with the bump in the dividend in the fourth quarter, it looks like you slowed that a little bit. I wanted to ask about that and then also the decision to bump the base dividend when you had been leaning more toward the share buybacks when you pulled back on the variable dividend. Why the bump in the base dividend rather than buying back more shares?

Shane Young: Hey, Mike. Shane here. I’ll take those two questions. Look, on the buyback, we remained active in the market during the quarter, but we were a little bit cautious. We were trying to kind of get a gauge whether winter and weather would materialize, and I think, as it didn’t, we decided to carry some of that cash over into year end. That’s why you saw the cash balance build up to around a $1 billion, which really puts us in good shape in what looks like it could be a soft gas market in 2024 to be a bit more aggressive on the buyback. So, yeah, there was a little bit of a timing element to that, I would say. On the base dividend, listen, in addition to the commitment to deliver 50% plus of our free cash flow to shareholders on an annual basis, we also remain committed to increasing the annual dividend responsibly on an annual cadence.

5% feels like a pretty good lift, but not overly excessive. So we’re happy with the 5% bump, and we get into next year, we’ll evaluate it again. If it makes sense to do it, we would expect to continue to do it on an annual cadence.

Operator: Your next question comes from the line of Scott Gruber with Citigroup. Please go ahead.

Scott Gruber: Yes. Good morning. Through your row development program, you’ve been able to push down your Delaware cost to several $1,100 a foot. As you’re reengaging in Anadarko, do you think you’ll be able to work down the cost structure into play? Are you thinking about pad size or rectifying operations or any other actions that you may need before you push down that $1,300 figure?

Blake Sirgo: Yeah. This is Blake. I’m happy to take that one. Yeah. We think there’s always room to push our efficiencies further and we do share a lot of our learnings across basins. But at the same time, the Anadarko is a different basin than the Permian. So it’s deeper, it’s higher pressure, the drilling can be more difficult. And really what we’ve seen from our Anadarko team is we ran a real consistent program in 2023, so consistent drilling activity and our crews did what they always do, they got better at it, and we saw our costs come down and get more in line. They’re already taking advantage a lot of the same pad efficiencies we see in the Permian. But if we saw opportunities to enlarge projects and get more economies of scale, we’ll absolutely take advantage of those.

Scott Gruber: Got it. And you guys have stuck with an estimate of about 5% deflation in service costs and material costs. But we’re now seeing several operators obviously take actions to reduce activity in the Marcellus. Do you think you’ll be able to see additional service cost savings on top of that 5%, especially in the Marcellus on your remaining activity?

Blake Sirgo: I mean, I sure hope so. The — we’ll see how the market plays out. They’re typically when more services become available, it does drive pricing down. We’ve been very strategic how we’ve gone into 2024 with our contracts. We’re very, very lightly contracted and that’s by design, so we can take advantage of any downswings. But at the same time, you know, who we work with and making sure we have premium service providers that share our safety culture and our drive for excellence is really important to us. And our service providers need to make a return also. So we’ll be working with them closely, and if there’s continued movement in the market, we’ll be there to take advantage of it.

Tom Jorden: But I don’t want that point to be lost. One of the reasons we have such flexibility in our capital allocation is because we’ve worked really hard over the last couple of years to have a great set of vendor partners and a very light amount of long-term commitments. So we really do have a lot of flexibility in both our drilling and completion services to pivot from one basin to another.

Operator: Your next question comes from the line of Kevin MacCurdy with Pickering Energy Partners. Please go ahead.

Kevin MacCurdy: Good morning. First, I want to say we appreciate the three-year outlook. I think you’re one of the few companies in your peer group with the confidence in your inventory to provide a detailed multiyear outlook. My first question is on that outlook. Are you assuming a similar capital allocation in 2025 and 2026 as in 2024? And under that scenario, when and at what levels does the Marcellus start to flatten out?

Tom Jorden: Yeah. The answer, Kevin, is no, we’re not assuming a similar level of allocation. That said, it’s a fluid, but the model that underpins that is a reallocated number.

Kevin MacCurdy: Okay. And under that three-year scenario, what happens if we have a bullish gas market in 2025 and 2026? Do you reallocate capital from the Permian and the Anadarko back to the Marcellus or do you increase your overall CapEx? I know you spoke about a contingency plan in 2024, but just thinking about how you would think about that over the long-term?

Tom Jorden: Well, you’ve left a very nice wide opening for me with that question, because I say, it’s always our best look at current conditions. So if we had significant recovery in the gas macro, which we hope and expect, our cash flow goes way up, and within that investment fairway of, I said, 40% to 70%, we probably would have the flexibility to look at increasing our capital. But none of that is enshrined in our current outlook, because we don’t, I’d say, there is not — there’s no hope in any of the outlooks around here, but we’ll react when conditions change.

Kevin MacCurdy: Great. Thanks for the detail.

Operator: Our next question will come from the line of Ati Modak with Goldman Sachs. Please go ahead.

Ati Modak: Hi. Good morning, team. Just curious how you view the macro setup for the gas markets here. What’s the risk of surprise in associated gas from the Permian and how do we work our way through that? Are you seeing sufficient signs of supply rationalization to suggest that we’re in a better environment for 2025?

Shane Young: Yeah. Hey. It’s Shane here. I’ll start off on that. Look, it’s very challenging today. And as we look at the storage numbers and the weather picture as it’s played out, winter to-date and the way the outlook is for the next several weeks, look, we could sort of end the winter at a pretty high spot on a historical basis. Production, on the other side, has been incredibly resilient, probably more so than many of us have expected. It’s great to see — to hear some discipline in the marketplace, but it’s unclear that it’s enough and it’s unclear that it’s sort of broad-based enough at this point. So we’re cautious on gas and you see that in our 2024 planning and budgeting. You see that in the way we manage our balance sheets. But if it does turn and when it does turn, we’ll certainly be prepared to react.

Ati Modak: Great. And then you talked about this a little bit, but maybe I can approach this in a different way. Your three-year outlook on growth is on relatively stable annual CapEx. Curious what factors you’ve baked into that growth outlook in terms of the incremental efficiency gains. What should we expect to hear from you on that front over this time period?

Tom Jorden: We don’t bake in any incremental efficiency gains. So we take all our most recent gains in our program. We kind of stress test those by going through them extensively to make sure they’re real and part of our program and then we build them into our forecasting. And so while our expectation is our teams will continue to drive efficiencies, none of that’s built into these projections.

Operator: Our final question will come from the line of Charles Meade with Johnson Rice. Please go ahead.

Charles Meade: Good morning, Tom, to you and your whole team there.

Tom Jorden: Good morning.

Charles Meade: I have two questions on the Marcellus and you’ve addressed some of this, but I just want to make one more run at it. If we look at the decrement of $435 million in CapEx in 2024 versus 2023, and you look at that versus you went from two rigs to one rig and one frac crew to maybe a half frac crew, it seems like the decrement in activity is smaller than the decrement in CapEx. And so what are the other pieces that complete that picture?

Tom Jorden: Well, one of the things that we see is we will finish the year with four pads waiting to be completed. So, a lot of what we’re doing in 2024 is setting up 2025. So, it’s not always showing up in the first year CapEx. With projects that have cycle times like ours and like everybody else’s, you really have to have a multiyear outlook on any plan. So a lot of that is a benefit of what we did last year that’s currently being completed and what happens next year is a function of what we do this year. So the annual snapshot on capital versus production is interesting, but fairly incomplete.

Charles Meade: Right. That makes sense. And then maybe one other question. You have on your slide, I believe it’s slide six, you show that 10% decline in Marcellus production for 2024, but then actually a slight incline for 2025. What’s the underlying price assumption for natural gas in that scenario where you grow again at 2025?

Tom Jorden: Well, we have lots of price assumptions. I would say we have strip. We run a 55-275. We run a 75-250. I mean, we have — we run 75-375 [ph]. I’m looking at our models now. I mean, we have a smorgasbord of price files that really set our kind of define the fairway of our economic analysis. But I would say this is probably based on the strip as a foundational forecast and then we run permutations from there.

Operator: I’ll now turn the call back over to Tom Jorden for any closing remarks.

Tom Jorden: Well, thank you very much for joining us. We look forward to continuing to deliver. As I hope you’ve learned from Coterra, we really appreciate your interest and love talking about results and intend to deliver them. So thank you so much.

Operator: Everyone, this does conclude our conference call for today. Thank you all for joining. You may now disconnect.