Coterra Energy Inc. (NYSE:CTRA) Q3 2023 Earnings Call Transcript

Coterra Energy Inc. (NYSE:CTRA) Q3 2023 Earnings Call Transcript November 7, 2023

Operator: Ladies and gentlemen, thank you for standing by. My name is Cheryl and I will be your conference operator today. At this time, I would like to welcome everyone to the Coterra Energy 3Q ‘23 Earnings Conference Call. [Operator Instructions] Thank you. I would now like to turn the call over to Dan Guffey, Vice President of Finance, Planning and Investor Relations. Please go ahead.

Dan Guffey: Thank you, operator. Good morning and thank you for joining Coterra Energy’s third quarter 2023 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 prepared 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 thank you all for joining us this morning. Coterra had an excellent third quarter, exceeding expectations across the board. This was the result of several factors, including outstanding performance from our top-tier assets and excellent operational performance from our organization. I want to particularly acknowledge our field employees and vendors, who are the driving force behind our outstanding results. Although we are pleased to announce these results, quite frankly, it’s what you should expect at Coterra and what we expect of ourselves. We are not interested in being average. These results are best understood within the framework of the core thesis of Coterra. With top-tier oil and natural gas assets, Coterra can flexibly allocate capital to take advantage of changing commodity prices, changing technical innovations and changing field conditions.

We work for our shareholders and we believe that they are best served by a disciplined approach that generates consistent, profitable growth. We do not manage the company around production targets. We manage the company to maximize the financial productivity of our assets. We seek to grow our per share profitability throughout the cycles, which is best achieved through a combination of prudent investments and direct shareholder returns, in the form of dividends and buybacks. We are problem solvers. Albert Einstein said, “It’s not that I am so smart. It’s just that I stay with problems longer.” At Coterra, we stay with problems longer. Staying with problems longer means that we do not simply adopt workable solutions. We demand perseverance in finding optimum solutions.

This is true with our technical challenges as well as our financial challenges. We do not adopt an A-priority, zero-growth posture and operational planning. No more or no less than we assume A-priority answers to technical problems before engaging in rigorous analysis. A key focus of our organization is iterative, operational and financial planning. We engaged in exhaustive planning iterations in an ongoing effort to maximize our capital efficiency, focusing both on asset productivity and cost optimization, which also allows us to analyze and model multiple options. Dwight Eisenhower said that, “in preparing for battle, I have always found that plans are useless, but planning is indispensable.” At Coterra, we build annual capital plans that have on-ramps and off-ramps.

By limiting our long-term commitments, we retained the option to pivot capital from one area to another as conditions warrant. Our history tells us that flexibility is crucial or we cannot predict the future. And it’s not the plans that are important, it is the planning. This planning process, combined with the high energy, innovative and curious organization is the core of Coterra’s strength. We do not intend to provide detail on our 2024 plans during this call. However, we are highly confident that our results will continue to be top tier, that our capital efficiency will continue to improve and that the quality and duration of our inventory will continue to be apparent. As we have previously discussed, we expect to enter the year holding our Marcellus gas production relatively flat as we monitor gas macro conditions.

By doing so, we can reduce Marcellus’ capital by at least $200 million versus 2023, while maintaining the optionality to pivot back to the Marcellus when gas markets structurally rebound. In February, we will provide an updated 3-year outlook. We do not expect significant deviations from our current strategy of allocating capital to its most productive use to achieve moderate disciplined growth. Under a moderate multiyear growth strategy, our corporate breakeven defined as the ability to generate excess free cash flow after paying our healthy common dividend, will remain below $50 oil and $2.50 natural gas. Before I turn the call over to Shane, I want to close with our answer to the question, why Coterra? Coterra is a new company and one that is unique in our space.

We have top-tier assets, a top-performing organization and robust revenue diversity. We operate among a field of great competitors, and we are here to compete. Coterra is designed to provide excellent financial and operational results through the cycles. Our goal is to make top-tier results routine. As I said, it is what you should expect of us because it’s what we expect of ourselves. With that, I will turn the call over to Shane.

Shane Young: Thank you, Tom and thank you everyone for joining us on our call today. This morning, I will focus on 3 areas: First, I will discuss highlights from our third quarter 2023 results. Then I’ll provide production and capital guidance for the fourth quarter, and update our full year 2023 guidance. Finally, I’ll review where we are on our shareholder return program year-to-date. Third quarter total production averaged 670 MBOE per day. Oil averaged 91.9 MBO per day, and natural gas averaged just over 2.9 Bcf per day. All production streams came in above the high end of our guidance driven by a combination of continued positive well productivity, coupled with faster cycle times that accelerated TILs. Turn-in-lines during the quarter totaled 46 net wells, 25 in the Permian at the high end of guidance, 14 in the Marcellus at the midpoint of guidance, and 7 in the Anadarko, as our Evans project came on a few weeks earlier than expected.

Turning to our financial performance. During the third quarter, Coterra reported adjusted net income of $373 million or $0.50 per share, and discretionary cash flow of $796 million. Approximately 64% of our revenues for the quarter were generated by oil and NGL sales. Accrued capital expenditures in the third quarter totaled $542 million, at the low end of our $540 million to $610 million guidance, and free cash flow was $250 million after capital expenditures of $546 million. Total cash costs during the quarter, including LOE, workover, transportation, production taxes and G&A, totaled $7.99 per BOE, down from approximately $8.27 in the second quarter. This was below the midpoint of our annual guidance range of $7.30 to $9.40 per BOE. One note on our deferred tax guidance.

Beginning in 2022 and with greater impact in 2023, new requirements under the Tax Reform Act of 2017 require Coterra to capitalize Section 174 R&D expenditures and amortize these expenditures over a 5-year period, rather than expensing them in the year in which they occur. Our third quarter 2023 deferred income tax ratio was negatively impacted by this new requirement. As such, we now expect 95% or more of our full year 2023 income tax expense to be paid during the current year. This 5% to 10% change and our percent deferred will have a minor impact on 2023 discretionary cash flow, but we felt it was worth clarifying on this call. Looking ahead, we estimate over the next few years, our percentage of income taxes to be current will be greater than 90%.

Looking ahead to the fourth quarter of 2023, we expect total production to average between 645 and 680 MBOE per day, oil to be between 98 and 102 MBO per day, and natural gas to be between 2.7 and 2.9 Bcf per day. We expect accrued capital in the fourth quarter to be between $460 million and $530 million, which includes the impact of infrastructure and non-operated activity shifting into the fourth quarter. For the full year 2023, today, we are increasing our production guidance. Our oil volumes are now expected to come in at 94.5% to 95.5% MBO per day, up 3% from our August guide. Our BOE and natural gas volumes are now expected to be 6.55 to 6.65 BOE per day, and 2.84 and 2.87 Bcf per day, up 3% and 1%, respectively, from our August guide.

Relative to our initial February guidance, Coterra’s full year 2023 production guide has increased 5% for BOEs, 7% for oil and 3% for natural gas. The incremental volumes were driven by an even split between better-than-anticipated well productivity and faster cycle times in the field. Based on updated guidance and recent strip pricing, we now expect to generate full year discretionary cash flow of approximately $3.5 billion, with more than 50% of revenue driven by oil and NGL sales. The company expects to invest approximately $2.1 billion or roughly 60% of cash flow, and generate free cash flow totaling $1.3 billion. On to shareholder returns. Last night, we announced the $0.20 per share base dividend for the third quarter. Our annual base dividend of $0.80 per share remains one of the highest-yielding base dividends in the industry at nearly 3%.

The Management and the Board remain committed to responsibly increasing the base dividend on an annual cadence. During the third quarter, despite relatively lower commodity prices and cash flow, Coterra continued to execute its return program by repurchasing 2.2 million shares for $60 million, at an average price of approximately $27 per share. In total, we returned 84% of free cash flow during the quarter. Year-to-date, including our base dividend and $385 million of share repurchases, we have returned $839 million or 91% of free cash flow to our shareholders. Taking into account recent strip pricing, buyback activity completed year-to-date and our expected base dividend for the year, we expect to return greater than 80% of our 2023 free cash flow to shareholders, well in excess of our 50%-plus minimum commitment.

Moreover, since instituting the buyback program in 2022, Coterra has repurchased a total of 64 million shares or 7% of our shares outstanding, for $1.6 billion at an average price of $25.72 per share. In summary, Coterra’s team delivered another quarter of quality – high-quality results, both operationally and financially. We look forward to a strong final quarter of 2023, which we believe should set a solid foundation for 2024 and beyond. With that, I will hand the call over to Blake, to provide more color and detail on our operations. Blake?

Blake Sirgo: Thanks, Shane. This morning, I will discuss our capital expenditures and provide an operational update. Third quarter accrued capital expenditures totaled $542 million, coming in at the low end of our guidance of $540 million to $610 million, primarily due to delayed infrastructure spend and lower non-operated activity, both of which we expect will move into the fourth quarter. As such, we are reiterating our full year 2023 capital of $2 billion to $2.2 billion, and continue to trend 1% to 2% above the midpoint. Looking ahead to 2024, we continue to expect a 5% dollar per foot decrease, based on leading-edge service costs and contract repricing. Of note, we continue to see meaningful price decreases in OCTG, rig rates and frac spreads.

However, other cost categories, including labor and fuel costs, remained resiliently high. As noted in our investor deck in the third quarter, our Permian and Marcellus frac crews averaged 17 hours per day, up 18% from a year ago and an all-time record for our pumping efficiency. The drivers of this improvement include larger project sizes, increased wells per pad, improved water sourcing and a focus on transition timing. Over the last few years, our company has achieved improved capital efficiency through the execution of longer laterals, combing window surface facilities and sign-offs. Our operations teams in all 3 bases continue to find creative and impactful ways to improve our capital efficiency. These gains couldn’t be achieved without the strong execution of our world-class field staff.

We recently added a seventh rig in the Permian Basin, a few months ahead of schedule. This was driven by a recent decision to simul-frac and derisk the timing of our largest 2024 project, the Windham Row, in Culberson County. Simul-fracking has the potential to decrease dollar per foot on this project by an incremental 5%, bringing the project’s total estimated cost savings to 5% to 15% versus our current Culberson County average. To our knowledge, this project will be the first all-electric simul-frac, powered directly from the grid. Currently, we are running 10 rigs, 7 in the Permian, 2 in the Marcellus, 1 in Anadarko, and 3 frac crews, 2 in the Permian and 1 in the Marcellus. When looking ahead to 2024, Coterra has fewer than 25% of its rigs and frac fleets under contract.

This provides significant optionality. We are in the middle of negotiations on a number of contracts, and we’ll provide a detailed update to February.

Tom Jorden: Thank you, Shane and Blake. Momentum at Coterra continues to build. We’re generating consistent, profitable growth. The company remains well positioned to deliver on its stated goals. We appreciate your interest in Coterra and look forward to further discussing our results during question-and-answer.

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Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Nitin Kumar. Nitin, your line is open.

Nitin Kumar: Hey, good morning Tom and team. Congratulations on a great quarter. Tom, I want to start with cash returns. As much as your oil performance has been impressive, as Shane mentioned, you are on track to return 80% of free cash flow this year. Some of your peers have increased the commitment or the percentage that they promised to give back. You are still at 50%. Just, if you could share some thoughts on how you are thinking about the cash return framework and could we see it evolve in 2024?

Tom Jorden: Well, I am going to let Shane carry this one over the finish line. But look, I am just going to say flat out, we are not interested in getting in an arms race of promises on cash return. I think you can look at what we have done. It’s nicely laid out in our deck, that we have a history of being serious about returning cash to our shareholders. But as you know, Nitin, we really value flexibility and I just don’t think it makes any sense to make, quite frankly, glorified promises. We would rather be measured by our results.

Shane Young: Yes. Thanks, Tom. I think Tom laid it out really, really well, Nitin. But I would just emphasize that for the third quarter, we returned 84% of our free cash flow. For the year-to-date, we’re well above that, over 90% of our free cash flow. And that 80% figure that I talked about earlier, that’s a number that sort of takes into account buybacks to date, plus dividends, including an assumed hold of the dividend in the fourth quarter and doesn’t assume any incremental repurchases. So that number could well go up higher by the time we get to the year end. If you look at the track record in the history, if you go back to the first quarter of 2022, till to date, you’ll see we’ve been anywhere from 70% to in excess of 100% of our shareholder returns as a percentage of free cash flow, really averaging a bit over 80% over that time window.

So I go back to what Tom says, looking at what we do, and judge us by those actions, but we are fully committed to returning capital in a good quantum to our shareholders.

Nitin Kumar: Great. Thanks for the answer, guys. As my follow-up, obviously, industry consolidation is on everybody’s minds recently. Tom, you were very systematic and disciplined at Cimarex when you were creating your Permian position, then with the combination with Cabot and the formation of Coterra, you took a slightly different approach to building a different company. So just if you could give us your thoughts on the M&A market, where you see Coterra fitting in? And what is your strategy around consolidation from here and out?

Tom Jorden: Well, Nitin, thank you for that question. Our strategy is simple. It’s consistent profitable growth. We want to generate financial returns through the cycles. We don’t want to be beholden to a particular commodity or a particular geography. We believe in operational excellence and think that being good at the business as a strong underpinning of any kind of financial runway. We don’t have a problem to solve. I think the combination of Cimarex and Cabot built one of the most resilient companies in our space. And hopefully, we are in the process of proving that to our viewers. But as we look at the landscape, we would view M&A solely as an opportunity but not a necessity. We don’t have a strategic goal around any kind of M&A, quite frankly, we’re cautious.

We’re cautious because when you invest through the drill bit, you can do that incrementally and you can pivot and in just as conditions change. M&A involves large episodic movements that can often catch you countercyclically. So we’re opportunistic. We’re never going to say never to anything. We look at it all. But we’re going to be disciplined. Shane, you have any thoughts on that?

Shane Young: No. Look, I would just echo that – look, the last month has seen some large-scale M&A, but really 2023 has been an active year for M&A throughout of all different shapes and sizes. And we’re always curious. And if things are out there, are always trying to figure out if there’s an opportunity to – for those things to help make us better over time. But clearly, year-to-date, we haven’t seen anything that sort of checked all the right boxes. And so we’re very comfortable with taking the business from where we sit today.

Tom Jorden: Yes. Shane said it right. It’s about getting better. And I’m particularly proud of the way this organization is performing, and very confident in saying we intend to make a routine. We would not put that at risk with something that interrupts our momentum, period.

Nitin Kumar: Great. Thanks for the answers, guys.

Operator: Your next question comes from the line of Umang with Goldman Sachs. Umang, your line is open.

Umang Choudhary: Hi, good morning. And thank you for taking my questions. My first question was on the Windham Row development. Can you provide any details on the expectation from the program? And any color you can provide on the rig ad and your plans to do this, the project, heading into 2024?

Blake Sirgo: Yes. Umang, this is Blake. I’m happy to take that one. As we’ve talked about, the Windham Row, is really our largest row project to date. It’s just taking all of our operational efficiencies and putting them in one place. So in several DSUs lined up together, it’s not what you would consider one giant cube development, if we’re prosecuting the Upper Wolfcamp across one big section and one big row. And by doing that, we can concentrate our rigs, our frac crews, we can co-mingle our facilities, and we can drop our infrastructure costs. So all that adds up to some pretty big cost gains. The decision to add the rig a little bit early was frankly just to get ahead of getting the wells ready. We’ve decided to simul-frac that row. And so simul-frac moves very quickly. You got to have all the wells ready and we just wanted to make sure we had plenty of buffer there. So that’s really the main driver.

Tom Jorden: It’s also an electric simul-frac, and that required additional lead time for our partner.

Umang Choudhary: I see. That’s really helpful color. I guess moving to your 3-year outlook, and we will wait for a fulsome update next year. But I wanted to get your high-level thoughts, I mean, this year, you have shown strong performance. Oil growth is 9% year-over-year close to 9% year-over-year. And then on Slide #14, you highlighted continued expectations for strong productivity in the Delaware going forward. How should we think about the evolution for the company over the next 3, 4 years? Any high-level thoughts you can provide there?

Tom Jorden: Well, I think you should think of it in terms of our history of behavior. We don’t manage the company by production goals. I think I was clear in my opening remarks on that. We really seek to fund very robust projects that not only deliver outstanding returns, but have remarkable windage if the commodity price will fall, so that we know that we’re getting a good return on our capital through the cycles as we can best predict them. So we said, so we decide how much capital we want to invest, what projects we want to fund, we do our very best job to come up with an estimate of what the production will be. And then we challenge our organization to overshoot that. And when they do, we don’t view that as a negative.

And so that’s the way we’re going to view our 3-year plan, and we really hope to be providing better and better guidance. We always like to get what we aim for, high or low. We want to hit what we aim for. And although we’re proud of outperformance, it means we need to go back to drawing board and do better estimation.

Umang Choudhary: That’s great answer. Thank you.

Operator: Your next question comes from the line of Arun Jayaram with JPMorgan. Your line is open.

Arun Jayaram: Yes. Good morning. I was wondering if you could – really appreciate the Slide 17, on the Windham Row, but I was wondering if you could give a sense of what you’re doing to de-risk some of the project timing and development of that large row development. In particular, I wanted to see if you could give us some insights on some of the learning from the Mint Julep project that you did this year, which maybe helps to de-risk this larger project?

Blake Sirgo: Yes, Arun, this is Blake. I’m happy to take that one. We’ve learned as we’ve expanded these rows bigger and bigger. And while it’s a big pretty slide and a long row, you need to remember this is kind of what we do day in, day out. We drilled DSUs all over the Permian, and we have to stay ahead of them no matter where they are. This is just putting them all in one big row so we can prosecute them as one project. There are lots of things we’ve learned along the way. SIMOPs is probably the biggest one by far. We built in a lot of timing estimates based on when we drill and then we frac and then we drill out our plugs, there’s a lot of timing scenarios we use, including what happens if something gets stuck, what happens if something goes wrong.

We call them bailout wells. We have another well ready to go that we can shift the operation to while we work on that well. And that’s really how we approach it. We built a lot of flexibility into the row development.

Arun Jayaram: And Blake, just as a quick follow-up, how many wells would you expect if timing goes as planned to come online next year because I think you just started drilling the row in the third quarter?

Blake Sirgo: All of them. It will be – the full row will come online next year, which is 51 wells. Yes, sorry. And there won’t be one big slug. It will, as we get further down the road this first well will be coming online.

Arun Jayaram: Okay. And then my second question, Tom, where do you stand in terms of the $200 million of capital that could be reallocated from the Marcellus to your other two assets? And maybe just a quick update on how Demic Township, how that could impact or influence that decision?

Tom Jorden: Well, I’ll take that in reverse order. We don’t see Demic being a material influencer, one way or another. We’re pleased to be returning there, but it’s not really a critical factor in any of our remarks. And then as far as the $200 million, Arun, we’re still where we’ve been, we have flexibility there. We’re analyzing our options. We’ve got every option in front of us and look really forward to discussing ‘24, when we’re ready to discuss it. I mean we’re working on our plans.

Arun Jayaram: Great. Thanks a lot, Tom.

Operator: Your next question comes from the line of Doug Leggate with Bank of America. Doug, your line is open.

Doug Leggate: Thank you. Good morning, everyone. Thanks for hop me on. Guys, I wonder if I could ask about the Anadarko, where it sits in your thoughts on relative capital allocation for 2024. And I guess my question is around – the guidance suggested no tills in 3Q, and yet, we obviously saw the activity there. So I’m just curious if your thoughts on the competitiveness of the Anadarko has stepped up a bit going into next year?

Tom Jorden: Well, thank you for that question, Doug. As you know, we love the Anadarko. It competes heads up. It offers market flexibility. It also is really coming back to force with some new targets, some new completion styles. The fact that we turned some wells online in the third quarter is just an outperformance of our execution. But I think you could expect a healthy Anadarko program next year. And it’s not out of love or affection. It’s out of competing for capital, and those projects are really competing for capital. And then the one other thing they’ve done is they’ve established repeatability. Now we’ve got a few behind us that have been repeatable, executed well, gone like clockwork, and that’s what we’re looking for.

Doug Leggate: I guess as my follow-on is kind of related, Tom. Thanks for the answer. So if I think about the indications on where costs are headed, capital costs are headed and all the moving parts in there, not just from yourselves but from your peers. And then I also stick with the mantra that your capital program is really driven by efficiency and not by growth. I look to 2024, and I have to consider whether your CapEx guidance either is low end of your current range or maybe have some downside risk, and I’m trying to understand, would you rather take those efficiencies and redeploy the capital and keep the capital the same? Or are you trending lower in your spending going into ‘24? Any early guidance will be appreciated.

Tom Jorden: Yes. I’m going to give you a very vague guidance here. We will take efficiencies every day we can find them. And to the extent that efficiencies mean we can do the same thing next year cheaper than we did this year, all else being equal. That’s a wonderful outcome, and we seek to find those outcomes everywhere we look, but that – you can infer what you will, with that $200 million, what that means. But it means we have more opportunities than we thought we would ever have because of efficiencies. We’re not prepared to say whether we’ll be flat, up, down, sideways. But I will say this, I think you can look for us to have a very strong 2024, based on the operational momentum, capital efficiency, asset productivity and operational execution that we have going on. It’s going to flow right into ‘24, and we will be able to do more with less.

Doug Leggate: Appreciate the answers. Thanks so much.

Operator: Your next question comes from the line of Scott Gruber with Citigroup. Scott, your line is open.

Scott Gruber: Yes. Thank you and good morning. So I want to touch on the strategy with the row development. It does differ a bit from peers, in that you’re generally focused on single zone development and not developing multiple benches. Can you just provide some more detail on what differs from a geologic perspective on the eastern side of the acreage? You mentioned on the Eastern side, co-development, is it necessary? Do you just see far less communication on the eastern side? What is the strategy, mainly a call on, really being able to leverage prior surface spending when you do develop these Tier 2 zones down the road, to offset the lower productivity. Just some more color on the strategy.

Tom Jorden: Yes. Well, I’m going to just say, first and foremost, as much as we talk about the Permian Basin, it’s highly variable and a lot of things change. depth, pressure, product type. It’s really not one single basin, but you have tremendous variation in stratigraphy and geomechanics and how rocks respond. For much, not all, but for much of our assets, we have come to the informed conclusion that co-development of vertical benches is not necessary, we can develop a particular bench and come back and develop benches above and below. Now that’s a function of frac barriers. It’s a function of reservoir performance. It’s a function of timing. But the fact that others see it differently, they’re playing in different areas of the basin.

It’s like me telling you that Mexico has the wrong word for beer. I mean, you get different answers depending on where you are. And even within the Windham Row, you’re going to see that the interference changes from east to west. So we are very confident in our approach. I’ll just leave you with that. That’s not to disagree or contradict anybody else’s, but we have a lot of data that makes us firm in the statement, that we can develop this single bench in the Wolfcamp without leaving behind resource above or below us. It’s also highly efficient to our infrastructure. But that’s a benefit, not a driver.

Blake Sirgo: Yes, I’ll just add to that, the row development does lay the groundwork for all future benches that we might develop. The infrastructure is in place. The tank batteries are in place. Our team has already modeled all those zones and how they can come on later and it will just drive down the dollar per foot on future projects. But as Tom said, that’s an outcome. That’s not the driver of why we’re developing and the way we are.

Scott Gruber: Yes. Do you have like a rough estimate in terms of savings on the subsequent developments when all the infrastructure and service spend has already sunk?

Blake Sirgo: No, I’d be nervous to quote a percentage on that one because it’s not in the immediate drill schedule, but it’s significant. It will move the needle.

Scott Gruber: Okay. Appreciate it. Thank you.

Blake Sirgo: Thank you.

Operator: Your next question comes from the line of David Deckelbaum with TD Cowen. David, your line is open.

David Deckelbaum: Thanks, Tom and team. Appreciate you guys taking my questions this morning.

Tom Jorden: Hi, David.

David Deckelbaum: Just curious, you all have demonstrated some pretty impressive well productivity gains, certainly over your base cases. I’m curious, as we progress into the back half or the end of ‘23 into ‘24, ‘25. How would you contextualize midstream constraints? I know, obviously, you have large-scale developments like Windham Row coming online. But we’ve heard by and large from many of the peers in the area, that midstream is creating a pretty big overhang around some near-term productivity. Could you contextualize, I guess, what you’re seeing and how you feel about the midstream setup going into ‘24 and ‘25 relative to your productivity?

Blake Sirgo: Yes, David, this is Blake. I’ll take that one. In relation to the Windham Row, but also all of our development in Culberson and Reeves County, we own and operate our own midstream systems. Actually, about 70% of our operated gas and our operated water goes through our Coterra midstream assets. So we have tremendous control. These are systems we have developed over years. Triple Crown, for example, in Culberson County, is tied into over five different processors that we can shift gas around to, which gives us a ton of reliability. In addition, we have multiple natural gas residue outlets. And that just gives us a ton of flexibility and confidence in being ready for these big projects. In New Mexico, we are a third party on the majority of our assets.

That requires a lot of planning for all the reasons you alluded to earlier. But we have some pretty good service partners, and we have found as long as we stay far ahead of our projects, they’ll be ready for us.

David Deckelbaum: Appreciate that. And then maybe just – so I better understand the comments around the Marcellus spend this next year. It seems like it’s being phrased as though it’s an option to spend $200 million less, but I guess, is that the correct way to think about it? Or is there really a $100 million plus of efficiency gains in there or just program changes just from designing better plans into next year?

Tom Jorden: Well, Dave, what I said in my opening remarks is as we throttle into the year, we’re currently in a cadence where we would – if we didn’t change, we would hold production flat and be able to realize those savings. But we also have on-ramps and off-ramps. I talked about planning. And one of the things that I’m most pleased about with our current program is, whether we’re talking about the Permian, the Anadarko or the Marcellus, each one of those plans has places where we can accelerate or decelerate if conditions change. We thought ahead, we pre-planned the way to react. And so right now, as we enter into 2024, we are going to be on a flattish-Marcellus cadence. And I would say you would probably see us increase rather than decrease from that if conditions warranted.

David Deckelbaum: Thank you, Tom.

Operator: Your next question comes from the line of Josh Silverstein with UBS. Your line is open, Josh.

Josh Silverstein: Hi. Thanks. Good morning guys. Just sticking with the Marcellus, the realizations have been pretty strong this year, and even better than the corporate realizations. I know some of this is from the NYMEX and fixed price contracts that you guys have. You outlined what you have for the rest of the year. Can you just provide us a little bit of insight as to what you guys have next year? And any thoughts on kind of what you can do for locking in strong basis relative to what the forward curve may be? Thanks.

Blake Sirgo: Yes, Josh, this is Blake. I will take that one. We don’t really see a change going from ‘23 to ‘24 in our portfolio. We are expecting to realize about 85% of NYMEX this year. That is driven by a big portfolio that’s anchored to a lot of out-of-basin indexes that give us exposure to strong pricing in the winter, and also a lot of NYMEX pricing built in there. So, we don’t see a big change from ‘23 to ‘24 and how that portfolio is managed.

Shane Young: And I would just say, even though the second quarter and third quarter, that realization is a little lower, if you look year-to-date, that’s right about where we are tracking year-to-date.

Josh Silverstein: Alright. Yes. Thanks for that. And then just on managing the cash balance, I think Tom, you said you wanted to have about $1 billion of cash on hand. Can you just talk about the flexibility in this? I think you still plan on paying down the third quarter maturity next year with cash. But could this cash also be used to support shareholder returns potentially above 100% of free cash flow if crude oil and natural gas prices move lower? Thanks.

Tom Jorden: Yes. I will jump on to Josh for a second here. So look, on the cash balance, again, if you look back over the last, let’s call it, 1.5 years or seven quarters, it’s sort of been between call it, maybe a little over $600 million, a little below $1.5 billion. So, we sort of gravitated around that $1 billion balance. I think we do want to be able to be countercyclical with regards to shareholder returns. So, if we are in a period like the second quarter, where free cash flow is a little bit tighter, we can certainly go beyond with that, in some cases, well beyond that in order to continue to support if we think there is intrinsic value in doing that with the share repurchase program. So, we certainly have that ability going forward.

The other thing I would just touch on quickly is next fall’s maturity, the 2024. And just to highlight, no decisions have been made on that. And so I think you sort of indicated that we would likely repurchase that or pay that off for cash. And that’s certainly one of the options, and we think we have a lot of different options. But I will just sort of temper that a bit and say no final decision has been made on that maturity.

Josh Silverstein: Got it. Thanks.

Operator: The next question comes from the line of Derrick Whitfield with Stifel. Derrick, your line is open.

Derrick Whitfield: Good morning and congrats on the strong quarter and update. Perhaps for Tom or Blake, one of the majors on the back of a recent acquisition talked about the potential to double or recovery with Newtek as a technical freight-winning organization that’s been in the basin for quite some time, are there any developments that you are aware of that could drive that degree of improvement in recoveries?

Tom Jorden: Yes, I will start that and Blake may want to comment. We followed that topic carefully. There are a couple of companies kind of talking about that. And I wish I could tell you that we had some back laboratory where we have our own version of it, but we don’t. We are watching very carefully. We certainly hope it’s true. But we don’t see evidence that it’s been field tested yet in any meaningful way. So Blake, do you want to comment?

Blake Sirgo: Yes. I will just echo what Tom says, we are highly curious. We asked about it all the time. But today, we haven’t seen anything show up in the data that would show some technologies being widely used. So, we will continue to pay attention.

Derrick Whitfield: Great. And as my follow-up, referencing Slide 17, I want to take it with really a different angle with my question. As you think about the go/no-go decision on co-development of Harkey and the Western spacing units of the Windham Row, what’s the downside of co-development from an upstream perspective if well level returns are largely consistent?

Tom Jorden: Yes. I don’t know that I see a downside other than midstream activity, and we do have a certain amount of capital that we want to deploy. So, if we were to co-develop, it would be increased capital. We have looked at this pretty hard. Certainly, within our assets, there are areas where there is more interference between the Wolfcamp and the Harkey, then there is areas where there is little observable interference. Even where we see interference, those Harkey wells are landmark, that helps, I mean even if you say, well you are going to drill the Wolfcamp, comeback sometime later and catch the Harkey. The returns on that Harkey layer, even with depletion effects are outstanding.

Derrick Whitfield: Great color. Thanks for your time.

Operator: Your next question comes from the line of Neal Dingmann with Truist Securities. Your line is open, Neal.

Neal Dingmann: Good morning and thanks for the time. Tom, my question, if I got asked on the capital allocation a little differently, you all previously had well above what I would call in prior, call it, a year or 2 years ago, what I always would deem is definitely well above-average production growth and what I would probably call then probably average shareholder return. And then obviously, here in the recent quarters, you have kind of reversed that where you now have well-above shareholder return, what I would call probably the average production growth. I am just wondering Tom, for you, again, is there a scenario where you would revert more back to that prior scenario?

Tom Jorden: In the prior scenario being above-average production growth, is that what you are saying?

Neal Dingmann: Yes, sir, and more back to the – instead of a 90% payout on the shareholder return, maybe back to, I don’t even know 50%, 60% or something?

Tom Jorden: No. I think we like our current approach. And under current conditions, I always want to say that, look, if the world changes, the last thing you should want me to say is, no, we are going to just keep doing what we are doing, even though the world has changed all around us. We have built Coterra to be flexible. But under current conditions, we are pretty solid with our current approach. Shane, anything you want to say to that?

Shane Young: No, I would agree with it. I mean I would only say, Neal, again, we have a lot of peers today that are probably more focused on just maintaining and keeping things flat. And so I think in that regard, Coterra is differentiated and that we can still generate consistent profitable growth in the current price environment that we sit in.

Neal Dingmann: Yes. Great add-on, Shane, I agree with that. And then second question, just on the cost reductions, very noticeable on the prepared remarks, you talked about the simul-fracs have potential for the 5% decrease, and taking the covering [ph] costs all the way down up to 15%. Can you remind me prior to this or a quarter or two quarters ago, into deflation next year? Are we all just thinking kind of maybe a 5% deflation, I am just wondering kind of how you are looking at sort of total, I don’t know if you want to call it deflation time, but sort of all in lower cost next year, versus maybe what expectations were a quarter or two quarters ago?

Blake Sirgo: Yes. For the total program, we are still estimating about 5% deflation going into ‘24. That’s based on what we know today, these simul-frac savings would be in addition to that. But that’s just for this one project, and we have a big portfolio, so it’s gone across the board savings. We are in the middle of negotiating our rig and frac contracts for ‘24 right now, and look forward to updating that when we put our plan out in February.

Neal Dingmann: Thanks guys. Great update.

Operator: The next question comes from the line of Matt Portillo with TPH. Your line is open, Matt.

Matt Portillo: Good morning all. Tom, maybe a question on the Anadarko Basin to follow-up on Doug’s question. It sounds like next year, you will have a relatively healthy level of activity. But I am just curious, maybe looking into the medium-term, it is an asset where you still have about 240 locations that compete for capital. It’s also a base that seems to be well situated to meet some of the pull demand from an LNG perspective. Just curious what you need to see either from a cost perspective or well productivity perspective or maybe a macro change, to see a healthy level of rig activity in the basin moving into the second half of the decade.

Tom Jorden: Well, look, what I would love to see is long-term LNG contract guarantees saw uplift in price, we would be willing to get after it. So, I am looking at Blake, getting him working on that. We do have an amazing asset in the Anadarko Basin. It’s ready to go. I mean we when we look at the Permian, the Marcellus, Anadarko, Coterra is very well positioned for exactly what was designed when we formed it. We can react to liquids prices or natural gas prices with a healthy inventory. When I say healthy, I mean a deep and robust inventory, and really, more and more people are seeing that in our asset base. But we would have that option. I mean that’s, Blake, do you want to comment on that?

Blake Sirgo: Yes. Just, the Anadarko is very well positioned for LNG. It’s got a straight shot to the coast. There is lots of new facilities coming online there. All of them intrigue us. As Tom said, we would love to find one that guarantees us some great tailwinds to our cash flow. We haven’t found that yet. But we are focused on how do we do an LNG deal that minimizes our total cost, but also gives us some flexibility. We do like to move capital around and we hate for the tail to end up wagging the dog on that.

Matt Portillo: Perfect. And maybe just a follow-up on gas specifically. Tom, just curious how you all are feeling about the hedge book heading into 2024. It still seems like it might be a bit of a transition year with some challenges on the inventory carryout from ‘23. And so just wanted to see how you all are thinking about your hedge profile for next year and then maybe longer term philosophy around hedging for natural gas.

Tom Jorden: Yes. Shane, why don’t you take that?

Shane Young: Yes, sure. So look, over the course of the last quarter, we did add some hedges to the book. And again, I think historically, we have been pretty consistent in messaging, we want to be somewhere between 20%, 25% to upwards of 50% hedged, any sort of forward 12 months, 18 months window. And so we try to get back into that posture. I think as you look today, we are positioned that way, plus or minus, around 25% to 30%, on the gas side, if you include the physical hedges and the financial hedges in concert. And we think that’s a good place to be, but we will continue to monitor it as we go. You will also find that if you just look at the shape of that hedge book, it is probably a little bit front half of the year weighted, a little less second half, not to the extreme, but there is a little bit of a slope to that profile.

Matt Portillo: Thank you.

Operator: Your next question comes from the line of Roger Read with Wells Fargo. Mr. Read, your line is open.

Roger Read: Yes. Thanks. Good morning. Just, come back to some of the productivity questions. There is obviously a portion of it you have talked about that’s above ground driven, and there is a portion that’s below ground driven. I think the above ground is not too hard to understand from a logistics standpoint, e-fracs switch over. But the below ground, what have you been able to do there that’s led to better performance per lateral foot?

Tom Jorden: Well, one of the things we have done, Roger, over the last few years, has really spent a tremendous amount of time studying the optimum development scheme for a drilling spacing unit. We have a little different spacing assumption than others. And I think we are – as we apply that throughout our portfolio, we are seeing ongoing benefits from it. We think that with fewer wells, we can extract the same amount of resource. Our machine learning team has been instrumental to Coterra in that understanding. And they continue to drive a lot of our thinking. It’s been a remarkable piece of technology to adopt internally, and it’s had direct benefits in our capital efficiency.

Roger Read: As we think about wider spacing, how does it factor in with the total inventory like the [Technical Difficulty] or are we thinking about enough of a run that you are not concerned over the next several years?

Tom Jorden: Yes, you were breaking up there, but I believe your question is with wider spacing, how does that impact the duration of our resource. We have modeled that into everything you see in our deck, that’s modeled in. And we don’t count number six on the map, quite frankly. Although everybody loves a high number there, we look at – I mean if we can drill fewer wells and get better financial returns and not leave stranded resource, that is the holy grail. And we think we are never there. Well, we are moving in that direction in a very positive way, and that’s part of what’s underwritten our results this quarter.

Roger Read: Alright. Thank you. Apologies for the break.

Operator: Your next question comes from the line of Leo Mariani with ROTH. Leo, your line is open.

Leo Mariani: Yes. Hi. I just wanted to ask on the seventh Permian rig here. It sounds like that was kind of always part of the plan and perhaps you guys just accelerated. So, I just wanted to confirm that was something that was going to be in place kind of all year in 2024. So, I mean it sounds like you are probably going to have a little bit more all-in Permian activity next year?

Tom Jorden: Well, I will tell you, if that was pretty big, there are a lot of people down in the hallway that have scars from us finding over that. But I will let Blake answer the question.

Blake Sirgo: Yes. I would say the real impetus was the Windham Row, like we have talked about. That’s a big project. We want to be well ahead of it to give us lots of timing. The drilling cadence associated with that project only how it’s picking up the rig early in ‘24, and we just decided to buy ourselves a little time and take it up early. We are able to contract a great rig with one of our strong service providers, and it was hot and ready to go, so we jumped on.

Leo Mariani: Okay. And so I just wanted to get a sense, I mean is that going to give you guys a little bit more Permian activity then just on average, it sounds like you are going to be running a little bit more equipment next year?

Tom Jorden: No. It really just accelerates the project. It’s not – it wasn’t a big material shift. We had plans to bring that rig next year anyway.

Leo Mariani: Okay. Understood. And then I guess, Tom, you talked about this a couple of times, but you got the multiyear guide, you are going to update that early next year, and it just sounds like clearly, you have outpaced expectations in 2023. It just seems like if we continue to see strong well results out of Coterra, you have got this guide of oil, of kind of 5% plus. If trends continue, it seems like it could be a little bit more than the plus as opposed to the 5%, as we roll into next year?

Tom Jorden: Well, we are currently 5% plus, and we look forward to discussing our plans when we roll them out. We are still having some iterations. But we are seeing great asset productivity and we expect any surprise to be the upside. Now that said, we also operate in the world where things go wrong. I mean there is – we are not immune from train wrecks, operationally. We avoid them as best we can. But I think if you look at our sector, any kind of operational interruptions are always part of our business. So, we like to promise what we think we can deliver.

Leo Mariani: Okay. Thanks.

Operator: Your next question comes from the line of Charles Meade with Johnson Rice. Charles, your line is open.

Charles Meade: Good morning Tom to you and your team there and thanks for going over the remarks [ph] here. This perhaps dovetails with that last question on your outlook for ‘24. But I want to start specifically with your 4Q oil guide, which was stronger than many of us from the outside looking in, we are expecting. So, perhaps this also fits with your earlier comments about volumes or volume growth is really an output, not a driver, we look at your sequential quarters over the course of trying to, we can see that, and that the oil rate has ticked up and it’s ticked back down, and you are going to have a big pickup for Q4. So, my question to bring it to a point is, how would you encourage us to look at this 4Q, your 4Q volumes? Is this one of the – a big uptick that’s likely to mean revert, or is this more along the lines of a new baseline that you that you guys are looking at that you are going to build on?

Tom Jorden: Well, we haven’t, as you know, specific plans for ‘24, but we carry a lot of operational momentum into ‘24. Now, that doesn’t mean that you take the extra rate and just keep it going up to the ride. When we talk about growth, we are talking about annual numbers. But what we are seeing with a lot of these projects that we discussed, such as Windham Row, is we are seeing less seesaw in that production profile. And we will be working hard to maintain that and ‘24 have less seesaw. We would like to have smooth operational cadence and kind of dampen the volatility in that production profile.

Charles Meade: And I guess maybe just for my follow-up, can you elaborate on what seesaw is?

Tom Jorden: Well, seesaw is up and down significantly quarter-over-quarter. But again, we are not prepared to discuss anything in specific about ‘24 on this call. I think our 3-year guide of 5 years plus – excuse me, 5% plus on oil is a reasonable expectation, and that’s kind of where we are studying kind of a starting point on the planning process.

Operator: Ladies and gentlemen, there will be no more further questions at this time. I would like to turn the call back over to Tom Jorden for closing remarks.

Tom Jorden: Well, I want to thank everybody for joining us this morning. Again, we are very pleased at Coterra, to be delivering excellent results for the third quarter, but I will finish where I have started. We expect this out of ourselves, and we think you should expect this from us. So, look forward to delivering consistent performance over time. Thank you very much.

Operator: Ladies and gentlemen that concludes today’s call. You may now disconnect. Have a great day.