Coterra Energy Inc. (CTRA) Earnings Call Transcript & Summary

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

Thank you, operator. Good morning, and thank you for joining Coterra Energy's Third Quarter 2024 Earnings Conference Call. Today's prepared remarks will include an overview from Tom Jorden, Chairman, CEO and President; Shane Young, Executive Vice President and CFO; and Blake Sirgo, Senior Vice President of Operations. Following our prepared remarks, we will take your questions during our Q&A session. As a reminder, on today's call, we will make forward-looking statements based on current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures were provided in our earnings release and updated investor presentation, both of which can be found on our website. With that, I'll turn the call over to Tom.

Thank you, Dan, and welcome to all of you who are joining our call this morning. As you saw from our release last night, Coterra had an excellent third quarter. Our volumes for oil, gas and barrel of oil equivalent came in above the high end of our guidance with capital coming in below the low end of our guidance range. Furthermore, we raised our production guidance and lowered our capital guidance for the full year. We expect 2024 to be our third consecutive year of delivering differentiated organic oil growth. This is made possible by our asset quality and growing capital efficiency, which are related to one another. Shane and Blake will walk you through our financial and operational results in some detail. Blake will also give you an update on our Windham Row project in Culberson County. In a nutshell, our results have been outstanding, and we expect similar projects to be a part of our program for many years to come. Slide 13 in our earnings presentation lists a few upcoming Culberson projects for future years. Our Windham Row has confirmed what we have stated all along. These projects are well calibrated and highly predictable. Although we are not prepared to be granular on 2025 plans, as you would expect, we hold significant optionality and flexibility. As an example, if we were to continue simul-fracking in Culberson County through 2025, it would increase our capital efficiency and result in an ongoing cadence of regular quarterly oil growth. We could achieve this within our framework of capital discipline and a conservative reinvestment rate. We are also pleased to highlight some of our recent New Mexico results in our earnings presentation. More to come on that from Blake. Although we remain constructive on natural gas markets, current prices have not recovered to the extent that would justify incremental drilling and completion activity in the Marcellus. We currently have no drilling or completion activity on our Marcellus assets. Additionally, we continue to curtail and shut in volumes, and we'll do so until we see materially better spot natural gas prices in the Northeast. 2025 Promises to deliver a more constructive natural gas market. The combination of growing LNG exports, increased electrical generation demand and the prospect of winter weather suggests a tighter supply-demand picture for natural gas in 2025 and beyond. In the meantime, we have other assets that are generating superior returns on our investments, and we have pivoted to them in 2024. You may also notice that we have recently entered into a handful of LNG sales agreements as illustrated by Slide 5 in our earnings presentation. These agreements are the result of our multiyear effort to further diversify our natural gas marketing portfolio by gaining price exposure to international markets. We are continuing to explore further opportunities along these lines. Blake will provide details on this. As we have repeatedly said, we manage our company by disciplined capital allocation, not by production goals. We have the luxury of doing so because we have top-tier oil and natural gas assets with a low cost of supply. These assets, coupled with our operational capabilities, can consistently deliver leading-edge returns on low corporate reinvestment rates through the cycles. Slide 6, which provides a snapshot of our inventory, shows that we can do this for many, many years to come. The robustness of our assets underwrites our shareholder-friendly return of capital program and our fortress balance sheet. Our approach to the business is simple. Build a top-tier operational team, a top-tier subsurface team, develop a portfolio of top-tier assets that offer geographic and commodity diversity and let data, value creation and sound financial analysis guide capital allocation decisions. Through it all, maintain a relentless focus on continuous improvement. At Coterra, it's progress over comfort. It's that simple, and we live by it. With that, I will turn the call over to Shane.

Thank you, Tom, and thank you, everyone, for making time to join us on today's call. This morning, I'll focus on 3 areas. First, I'll summarize the financial highlights of our third quarter results, including where we finished the quarter from a credit and liquidity perspective, then I'll provide production and capital guidance for the fourth quarter as well as provide an update for the full-year 2024 guide. Finally, I'll provide highlights from our continued progress on our shareholder return program. Turning to our strong performance during the third quarter. Third quarter total production averaged 669 MBoe per day with oil averaging 112.3 MBo per day and natural gas averaging 2.68 Bcf per day. All 3 came in slightly above the high end of guidance, driven by timing of operated and non-operated volumes as well as strong well performance. In the Permian, we brought online 24 net wells, near the high end of our 15 to 25 net well guidance. This includes 16 net Bone Spring wells across Lea and Eddy Counties and 8 net Windham Row wells in Culberson County. In the Anadarko, we brought online 5 net wells in our liquids-rich Updip area. While in the Marcellus, we brought online 7 net wells in mid-September. During the third quarter, pre-hedge revenues were approximately $1.3 billion, of which 75% were generated by oil and NGL sales. In the quarter, we reported net income of $252 million or $0.34 per share and adjusted net income of $233 million or $0.32 per share. Total unit cost during the quarter, including LOE, transportation, production taxes and G&A totaled $8.73 per BOE, near the midpoint of our annual guidance range of $7.45 to $9.55 per BOE. Cash hedge gains during the quarter totaled $28 million. Accrued capital expenditures in the third quarter were $418 million, below the low end of our guidance range as we spent less on midstream infrastructure and SWD capital. And also made the decision early in the quarter to drop our Marcellus rig. We had originally planned to have the rig running through year-end. Discretionary cash flow for the quarter was $670 million, and free cash flow was $277 million after cash capital expenditures of $393 million. We ended the third quarter very well positioned from a balance sheet perspective having 0.3x net debt to LTM EBITDA ratio and approximately $2.8 billion of liquidity after retiring a $575 million debt maturity during September. Looking ahead to the remainder of 2024. During the fourth quarter of 2024, we expect total production to average between 630 and 660 MBoe per day, oil to be between 106 MBo and 110 MBo per day and natural gas to be between 2.53 and 2.66 Bcf per day. In other words, we expect oil volumes to be down approximately 4% quarter-over-quarter as part of the natural cadence of our operations. This is a product of a combination of TIL timing during the fourth quarter, completing a portion of the Windham Row that was not simul-frac as well as having limited frac activity in the Anadarko during the fourth quarter. Given our curtailed volumes, we expect natural gas to be down approximately 3% quarter-over-quarter. We continue to monitor gas fundamentals to maintain the optionality to respond to signals on a month-to-month basis. Regarding investment, we expect total capital expenditures in the fourth quarter to be between $410 million and $500 million. Yesterday, we increased our full-year 2024 oil production guidance range to between 107 and 108 MBO per day for the year, up approximately 0.5% at the midpoint from our August guidance and up 5% from our original guidance released in February. We also tightened our full-year 2024 BOE and natural gas production guidance ranges, both up 1% at the midpoint from the August guide. Based on what we see the full year today, we are lowering our capital guide by $100 million at the high end and $50 million at the midpoint to $1.75 billion to $1.85 billion for 2024. This is 14% lower at the midpoint than our 2023 capital spend. This change, along with increased production, reflects continued meaningful improvement in Coterra's capital efficiency. Our 2024 program now modestly increases capital allocation to the liquids-rich Permian and Anadarko basins, while decreasing capital by approximately 65% in the Marcellus year-over-year. Moving on to shareholder returns. During the third quarter, we continued to see attractive value in our own shares and repurchased 4.3 million shares for $111 million at an average price of $25.15 per share. Last night, we also announced a $0.21 per share base dividend for the third quarter, which annualizes to $0.84 per share for the year. This remains one of the highest yielding base dividends of our peer group at over 3%. In total, we returned $265 million to shareholders during the quarter or 96% of free cash flow. We remain committed to our strategy of returning 50% or more of our annual free cash flow to shareholders through a combination of our healthy base dividend in our share repurchase program. Year-to-date, we have returned 100% of free cash flow to our shareholders. In summary, the third quarter, again, delivered excellent operational and financial results. Our fourth quarter activity schedule will position us for a strong start heading into 2025, where we maintain significant flexibility with regard to capital allocation. With that, I'll hand the call over to Blake. Blake?

Thanks, Shane. Our third quarter was another active quarter at Coterra. This morning, I plan to cover our new LNG agreements, Permian activity and cost update, along with overviews of Marcellus and Anadarko activity. This quarter, Coterra executed 200,000 MMBtu per day of LNG sales commitments, split evenly between European and Asian markets with first sales in 2027 and 2028. These agreements represent almost 2 years of work by our marketing team to survey the LNG landscape and find deals that best enhance our portfolio. These commitments are netback sales deals directly linked to JKM, TTF and NBP indexes and will be sourced from Coterra gas in the Permian, Anadarko and Marcellus. The gas sold under these agreements has no FID risk, as our counterparties are currently lifting cargoes from existing and operating facilities along the U.S. Gulf Coast. Lastly, these deals are with strong, established counterparties that Coterra is excited to partner with for many years to come. When we combine these agreements with our existing LNG deal at Cove Point, Coterra will have over half of Bcf of gas per day on the water starting in 2028. This is another step for Coterra, as we continue to leverage our multi-basin gas portfolio to maximize premium pricing and diversify our future revenues. In the Permian, we are currently running 8 drilling rigs and 2 frac crews, and our ops team posted another quarter of outstanding results. While our operated production came in where we expected with our increased efficiencies, we did see a nice bump in our Permian non-operated production with several projects coming in sooner than expected, leading to a beat above our high end of guidance. As Shane noted, due to the planned transition from simul-frac to zipper-frac for a portion of Windham Row during Q3 and limited Anadarko frac activity, we are forecasting a reduction in volumes for Q4. However, I'm pleased to report that Windham Row is ahead of schedule, below cost, and initial production results look strong. We look forward to sharing a final Windham Row update next quarter when all 57 wells are online. While Windham Row has been a critical project for Coterra in 2024, the rest of the Permian portfolio has also had a banner year. Our drilling and completion operations in our New Mexico Bone Spring program is having a great year with our drilling feet per day up 26% and frac pumping hours up 23% compared to a year ago. This has been accomplished by focusing on increasing our wells per pad and lateral lengths as well as a new zipper-frac initiative focused on reducing transition times between stages. This competitive cost structure is paired with some strong well results we are seeing in our New Mexico program. While Coterra has had great success in our Wolfcamp program in New Mexico, going back to 2010, we are still learning new things as we expand our developments across the liquids-rich strat column available to us in our New Mexico assets. A recent result we are highlighting is our Dos Equis project in Lea County, where we brought on 2 first Bone Spring wells at 4 wells per section and are seeing initial per well results comparable to the Upper Wolfcamp. This result, along with several great second Bone Spring sand results in the county are underscoring the value we see across our New Mexico position. Turning to Permian costs. In 2023, our Permian average well cost was $1,200 per foot. Driven by efficiency gains and moderately lower service costs over the last year, our 2024 Permian dollar per foot is expected to be $1,050 per foot, down 12% year-over-year. As we look forward, our leading edge costs are below $1,000 per foot, 5% to 10% lower than 2024. We define leading edge as current market rates and efficiencies with no projected deflation or further performance gains. As a reminder, when we share our full-year total well cost dollar per foot, we are including our all-in cost, which include drilling, completion, facilities and flowback. These are actual costs based on frac end date and not type curves, which directly reflect the capital spent on each project. While we are proud of our cost performance and always looking to do more with less, cost is not the sole driving metric at Coterra. Our goal is not just to be low cost, it is to generate maximum value. Total return on investment is the only lens we use at Coterra. In cooperation with our machine learning team, our reservoir engineers iterate frac design and well spacing to maximize the capital efficiency and net present value of every development. As you can see on Page 14 of our newly released deck, the result of this rigorous analysis is the combination of competitive costs and top-tier productivity in the Delaware Basin. One component of our fully burdened reported well costs are our facilities, which are constantly evolving to ensure compliance with an ever-changing regulatory landscape. Our new tankless battery designs comprise all our greenfield and most of our brownfield battery projects. This new design eliminates over 90% of the emission devices compared to a standard tank battery and greatly reduces the risk of fugitive emissions. Coterra has been implementing this design over the last 5 years. And today, almost 60% of our Permian oil production is flowing through tankless facilities. Innovations like this are part of our unwavering standards of operational excellence to ensure we are responsibly developing our assets in and around the communities where we operate. In the Marcellus, as a response to severely depressed pricing in the Northeast markets, we are currently at 0 drilling or frac activity. Going to 0 activity would not be possible without our Marcellus operations team developing new and creative methods to transport and dispose of produced water without relying on continuous frac activity. This thoughtful water strategy is what has allowed us to obtain the full-capital flexibility we price in our multi-basin portfolio and has allowed for improved capital efficiency across the Coterra platform. Our first round of lower Marcellus projects in the Dimock Township are complete with strong execution from our drilling and completion teams. We look forward to bringing these wells online in the coming months pending an improvement in Northeast gas pricing. We are continuing our month-to-month curtailment in the Marcellus with a planned 340,000 MMBtu per day gross and 288,000 MMBtu per day net shut in for the month of November. This volume represents a part of our sales portfolio tied directly to Northeast local pricing. We will continue to monitor pricing and make our curtailment decision 1 month at a time. We remain constructive on long-term gas markets. However, until demand catches up with plentiful pent-up supply, you can expect Coterra to continue to leverage its multi-basin, multi-commodity portfolio and continue to be disciplined allocators of capital with a focus on full-cycle returns. In the Anadarko, we continue to run 1 rig and completed 5 wells in the third quarter. Operational consistency is paying off in the Anadarko, with several strong projects coming online in 2024. Keeping a rig running and stacking together completion activity has allowed us to gain efficiency and minimize well problems. Despite natural gas headwinds, the liquids production in the Anadarko revenue stream has buoyed well economics and returns. Lastly, I'd like to commend our operating teams in all 3 business units, as they continue the trend of excellent execution and set us up for a great 2025. With that, I'll turn it back to Tom.

Thank you, Shane and Blake. As you can see, we've got a great momentum behind us. And with that, we'd be delighted to take your questions.

[Operator Instructions] We'll take our first question from Doug Leggate at Wolfe Research.

Gosh, Tom, your prepared remarks, it was quite intriguing to hear you say if we decided to continue with simul-frac, our capital efficiency would improve materially in 2025, just to put words in your mouth a little bit. Why would you not continue to simul-frac in 2025?

Well, we do have a portfolio, Doug. I would say that is a great question, and we're asking that of ourselves. I will answer that saying we're watching the oil markets. We're very constructive on all markets. But we're also wanting to have contingency plans in place if we see recovery in gas markets. So -- if we had to make a call today, which we do not, but if we had to make a call today, that's what we do. We have the program teed up, ready to go, and yes, we're just going to -- yes, we really like to maintain flexibility up until that point where we had to make a rock-solid commitment and steer the ship.

I guess it's a tricky follow-up question, if I may then, Tom, which is really this broader issue of capital allocation. And I guess you've kind of touched on it with the Marcellus optionality, but your oil production growth is again significantly beating, I guess, your indicated guidance. Your 3-year plan, I guess, you'll roll out early '25 again. It seems to us that you've got a lot of options to perhaps drop the capital, maintain the original guidance. And I just wonder if you could walk us through the -- what are the puts and takes on how you think about relative capital allocation across the 3 assets? Because it seems to me your optionality has probably never been better at this point.

Well, Doug, I mean, I will just repeat what you've heard us say. First thing we do topline is make an estimate of what our cash flow will be given the forecast of commodity prices and activity and results, and it's an iterative process, and then, we decide how much we want to invest. And we're -- we want to maintain a return of capital commitment. So we're typically in that 40% to 70% band. We've been on the low end of that and probably will be on the low end of that -- lower end of that. And then we calculate what our best returns are, and we see what our production will be. We'll also look at severe downside pricing and make sure that if we were to see declining prices, we would still get well in advance of our cost of capital. And with our cost structure and asset performance and capital efficiency, we're currently in a situation where we can drive that oil price down to $50, some -- in many of our projects sub-$50, and we would still get a return on capital that looks attractive to us. So growth is an output, and our check against do we want to do that or throttle back forward -- throttle further is really based upon that draconian downside. If we are well above our cost of capital, and we feel confident about that at the most draconian downside pricing, and we're within a capital return and cash flow reinvestment rate that we think maintains that discipline, we let the ship sail.

We'll move next to Arun Jayaram at JPMorgan.

Tom and team, I was wondering if you could give us a sense of how your returns from the Harkey shale interval are comparing and competing for capital with the Upper Wolfcamp. And -- perhaps going on in the Permian, just talk a little bit about the implications of the first Bone, second Bone results in Lea County and the implications for that.

Yes. Look, basin-wide, and of course, averaging is always difficult. And basin-wide, we would say the Harkey is outstanding, but slightly less than the Upper Wolfcamp. It depends where you are, but that's the answer. And then we're also seeing some -- as we said, some really nice results from that section above the Harkey, second Bone, first Bone in particular areas of the basin. So look, it's just a question of A++, A+ or A, these are all A-grade returns and delighted to have them.

Fair enough. Tom, Coterra is a large employer, community player in the state of New Mexico. I was wondering if you could just talk about some of the regulatory risk that was raised recently around potential setback rules in the New Mexico legislature. I think these are pretty preliminary in nature. But I was wondering if you could talk about your understanding the situation and potential risks to Coterra if you see them.

Yes. I mean, in a nutshell, I think that story was very overblown. Yes, there's always legislative studies. There's always committee discussions going on. We don't expect the setback issues that were in the media the week ago to be materially implemented. New Mexico, 50% of the state revenue or just about 50% comes from oil and gas revenue, and a setback rule like that would be very damaging to state revenue. That said, we think New Mexico is a very responsible regulatory environment. They hold our feet to the fire, both on emissions and environmental compliance. New Mexico is not the easiest place to operate, but I'll say this, it's a fair regulatory environment with really tough standards. But from time to time, you're going to have these things crop up in any democracy. I mean, good lord, look at some of the -- go back 3 or 4 months and some of the proposals that have been made in the national media in the political campaign, and we all know that it's just talk. We don't think that the setback rule is a serious risk to our industry at this time.

Next, we'll go to Nitin Kumar at Mizuho.

In your prepared remarks, you talked a lot about the capital efficiencies that you've seen, obviously, 12% higher oil production for 14% less CapEx. You mentioned faster wells or drilling efficiencies. You mentioned a little bit better productivity, and I believe, some OBO as well. Could we get a breakout of what are the real drivers of this incremental capital efficiency? And what I'm really trying to get at is how sustainable are these into '25 and beyond.

Yes. I'm going to turn it over to Blake, but I want to make 1 comment before Blake jumps in. Part of our outperformance on oil volumes is because of our efficiency of operations. And one of the things at Coterra with our balance sheet and our stable cash flow, we have the luxury to have very stable field operations. And if we were to throttle back it would lead to loss of efficiencies and actually cost us something. So whether it's running a simul-frac crew full time or our current operational cadence, we have this organization and operation at a point where our oil growth is really a function of cost savings from our efficiencies. But Blake, I'm going to turn it over to you.

Yes. Thanks, Nitin. It's a really good question, and it's -- to be honest, it's not always super easy to decompose because, like Tom said, we focus on operational consistency, constantly improving our performance, going faster all the time. But we do look back on all these things. And that's really how we ground truth our results. If I really had to take '24 and look at it in a nutshell to date, I'd say about 2/3 of our beats are coming from timing, so going faster. But we do have some nice productivity beats coming as well, and that's really the other 1/3. And so we try to bucket those that way. Your other question, just how long can this go on? We're always asking that question. Our standard at Coterra is operational excellence. We want to be the best at everything we do, which means what we're doing today is not good enough. And so our teams are constantly challenged to find new ways. It always feels like there's not a lot of meat left on the bone. But if you told me a year ago we'd be here today, I would have lost that bet. Our teams keep finding ways to push the envelope, and I won't be surprised if they find more in '25.

Nitin, we were asked that question around this time last year as we had sort of continued to up the guidance for the year. And last year, the answer was really closer to 50-50 between the 2. My sense is this year with simul-frac and with the increase in pump hours that the team has been able to achieve that that's what's really skewed that and weighted into that 2/3, 1/3 that Blake talks about in terms of outperformance in 2024.

Great. I'm going to stick with costs and efficiencies. I imagine it will happen more as the call goes on. I couldn't help but notice that the Culberson County well costs are at $860 per foot, which, if I remember correctly, was the high end of the savings you expected from row development. So I just wanted to see if -- again, how repeatable is that sort of $860 per foot? And then two, you talked about not being fully committed to simul-frac just yet. If you were not to use simul-frac on a pad or a project, what would be the savings you would lose?

Well, that's about $30 million a year, give or take, it would cost us on a simul-frac. And I want to be clear on what we said. We're not prepared to be granular on 2025 plans. Don't confuse that with anything other than literally what that means. So we'll release our 2025 plan next quarter. But Blake, why don't you...

Yes. I think you read into that well, Nitin. I would say we are comfortable saying we are at the high end of our projected savings on Windham Row. It's gone really, really well. And so the forecasting costs go forward in Culberson. If we chose to pursue that type of program, we've laid out other row developments we see coming, you would see that cost being repeated over and over. And so that's really the tie between those 2 things. As far as what if we went back to zipper-fracking in Culberson, what could that look like? We would lose at least $25 per foot. That's our simul-frac gains. There's also a few other gains in infrastructure and facilities that would back off of that, but that's probably about as close as I can get right now.

We'll move next to Neal Dingmann at Truist Securities.

My first question is on your Anadarko Basin specifically. Would you say that any of your future plans there, maybe next year or year after, are at all limited by the total lease position? And if so, would you all considered bolting on or adding larger patches in order to run a steadier program there?

Well, Neal, at our current rate of investment, we've got a deep and long inventory in the Anadarko Basin. But to your real question, yes, if we could acquire additional assets in the Anadarko in a bolt-on capacity, and they competed for capital with our existing inventory in some reasonable timeframe, we would definitely consider that.

Okay. That makes sense. And then, Tom, just moving to just sort of broadly production shareholder returns specifically, you all continue to nicely generate, I'd say, higher growth than the average E&P and continue to pay out a bit higher percent free cash flow than the average E&P. I'm just wondering, do you anticipate future production payout continuing to be a bit higher like this? Or again, is that, as you were saying earlier, just sort of predicated on what the environment is next year on both those sides?

Neal, I'll maybe start off on that a little bit. I mean, the way we think about buybacks and then shareholder returns in aggregate is starting with a base of 50% plus, so that we hold dear. Above and beyond that, as we think about buybacks, there's really 2 things, what are the other options outside of buyback? And with regard to the buyback, I think we've talked about focusing on 3 things. One, what's the intrinsic value? And is that attractive? And I think clearly, by our actions, we believe that to be the case and have all year. Two, what is the free cash flow profile looked like, not just in that quarter, but really over the next 3 or 4 quarters? And does that support an active buyback program? And then three, what's our liquidity position? Do we have enough liquidity? And as we talked about earlier in the year, we came into this year with about $1 billion of cash, and we've been pulling that down a little bit slowly leaning into the buyback program. Yes, today, we're around $840. But that still gives us more leverage and ability to lean in if we want to and potentially go down as low as the $0.5 billion area.

We'll move next to Kalei Akamine at Bank of America.

Sorry about that. I was on mute. My first question is on capital efficiency. Slide 19, it's a nice one that shows the breakdown of the Row savings and the frac operations are a big part of that. The leading edge, however, is trimul-frac. So wondering any thoughts on pushing those fracs even harder? Or do you think that would be too disruptive to the program that you guys have built?

No, that's a good question, Kalei. I mean we -- I can tell you, we look at everything. We're not scared at trimul-frac or anything. The -- as we've talked about before, most of our assets in the Delaware Basin are pretty deep and pretty high pumping pressures. And so there's a real balance between the simul-fracs and trimul-fracs and really understanding your projected downtime versus your cost savings, and you have to walk into that very carefully or you can think you're saving money, but really you're just going faster, potentially at an even higher cost. And so we're always studying those things. We think we've got simul-frac in a really good position in Culberson County. We've demonstrated the cost savings, and we know what those are go forward. But we'll always look at anything if we think it's really going to save money.

Our understanding is that water access is a big enabler of trimul-fracs. Are you set up waterwise to pursue that kind of program?

Yes. In Culberson and Reeves County, we control our SWD systems completely. And these are on-demand live systems. We can deliver water anytime anywhere. We also control our power grids. And so we're able to deploy all the horsepower we need to move that water around. So that would not be an issue.

My second question is about LNG. Our understanding is that your new contracts are a synthetic arrangement, which isn't that familiar to us. Can you kind of help illustrate how the netbacks are going to work? For example, is it JKM less some kind of fixed costs? Does the buyer have the FTE on the pipelines? I think we're all looking for a way to value this.

Yes, Kalei, I wish I could disclose those things to you. We've kind of put out as much as we can on these deals. What I'll say at a high level, these are physical gas sales directly tied from our wellhead to these foreign indexes. The path we're taking for each one is different on how we're getting there. Our focus though was to minimize variability as much as possible, so we're really just rising and falling with these foreign indexes. And we achieved that on all these deals, and they're true netback sales deals.

We'll go next to Scott Gruber at Citi.

Maybe I'll try the same question a little different way. At current global gas prices, would you be able to say how your gas realizations would improve if these contracts were enforced today?

Unfortunately, I can't quote that. I can tell you I wish they were enforced today.

Yes. Okay. Fair try. And maybe just turn to gas hedging strategy. You guys added a bit to your hedges here in the quarter, but just a little bit -- can you just discuss how you're thinking about hedging on the gas side in the current environment? Obviously, there's a big debate around where gas prices go next year. We're curious about your updated thoughts on hedging in the current environment.

Yes, absolutely. I'll start off with some comments that probably just apply broadly around hedging as it would generally try to be 20%, 25% at the low end, up to 50% at the high end in terms of the hedge position for the next 12 months, and then, we may sort of begin to layer in even beyond that with some small volumes as we build up, and that's where we sit today really on both commodities. On gas, in particular, I would say, we've got a little bit of a blended strategy of financial hedges that you see that are roughly 15% of the portfolio's expected production today. But at the same time, Blake and his marketing team are constantly out thinking about physical hedges as well, direct deals with end users and trade houses and other parties. And so -- and that represents roughly another 15% of our volumes. So in combination, as we sit today, you see us kind of hovering around 30% for the next 12 months, maybe 12 months plus a little bit into 2026.

We'll go next to Matt Portillo at TPH.

2 high-level questions for me. Maybe first starting off in the Permian. In Q3, you had very strong gas volume growth quarter-over-quarter. Just curious if you might be able to expand a bit behind the drivers on that. And then as we look forward with Matterhorn online, are you expecting any additional gas uplift in the coming quarters? Or because of your flow assurance, you had very little gas constraints year-to-date?

Yes, Matt, this is Blake. I'll take that one. Permian Q3 gas, there's really -- the only story there is some surprises in GOR to the upside, not a little stronger gas production than we were thinking from some wells. No real operational overprint going on there. As far as flow assurance and Matterhorn coming online, we've had flow assurance this whole time. That's #1 for our marketing team. We flow the Mcf first, and price is second. So it hasn't been a flow assurance concern, but we do have a piece of our portfolio that is settled at Waha. And so if nothing else, we're excited to maybe get a little -- something north of 0 would be great.

Perfect. And then maybe turning to the Marcellus. Just curious if you might be able to comment on, as we kind of think about the Q4 timeframe, the wells you've got in Dimock, the 11 wells. When you bring those on, is the plan to dewater them and then shut them back in to kind of push the volumes into 2025? And I guess, specific to '25, with the lack of drilling and completion activity at the moment, how should we think about the time from which you pick up a rig to when we might see a volume impact if you do decide to pick back up activity next year?

Well, first, on the -- yes, we are opening the wells to dewater them. That is part of our strategy. I think it's important to note, once we've drilled and completed wells, the capital spent, and we look at every molecule of gas in the Marcellus is the same, and so we manage the curtailment as a field. The most cost-effective way to do that is how we look at that. We don't really differentiate between TILs and base wells. So we will dewater those. And like I said in my script, this is month-to-month. We're playing this month-to-month. As our Northeast exposure moves up and down, we're making decisions on curtailments. As far as rig to volume, we -- Tom has pounded into all of us. We have on-ramps and off-ramps. That's how we build our capital program. And so we have on-ramps in the Marcellus. Should we -- should gas prices respond, we will be there to take advantage of it.

We'll take our next question from Leo Mariani at ROTH Capital Partners.

I just wanted to ask a follow-up on the discussion around capital efficiency here. So obviously, your CapEx has been coming down here in '24, which is certainly a nice trend to see and your volumes have gone up. So -- I know you have a -- kind of a 3-year outlook out there, which presumably you'll update early next year. But should we be thinking at this point in time that the CapEx and the 3-year outlook is biased to the lower end based on the efficiencies? I assume a lot of these are going to be recurring over the next few years.

Yes. I would -- Leo, this is Blake. I would just answer that with, yes, the efficiencies we are realizing are repeatable, and we bake them in as we go. And so if we updated that same 3-year guide today, it would look better. But that's also highly dependent on what we choose to do in 2025, and we're not ready to disclose any of that yet.

Yes. Let me just add to that. There are other elements in drilling completion efficiencies. We have midstream investments that we make. We have outside operated investments. And part of our capital reduction this year was due to laying down our Marcellus activity, meant that we spent less on what we had planned on some water infrastructure and to support our drilling program. So there's a lot of moving parts to this. In general, yes, we're achieving greater and greater capital efficiencies. But you can't always just connect 2 points and draw a straight line in the future.

Okay. That's helpful color for sure. And then I just wanted to get a little bit more thorough thought on M&A strategy. Obviously, the balance sheet is in terrific shape at this point in time. You just paid off another chunk of debt here. So as you're kind of thinking about allocating capital in terms of your free cash flow, how much does kind of M&A sort of to play into that? Are you still looking at kind of a number of deals out there? You did mention the Mid-Con deal could be possible. But do you think that there's other maybe deals also in the Permian that could fit for you folks over time? And are you still kind of seeing a lot of deal flow?

Yes. I want to just -- what I said on the Mid-Con deal was we would consider a smart bolt-on. Look, let me just answer that question in broad context as what would really cause us to stretch. We talked about -- last quarter, I spent a fair amount of time in my opening remarks talking about our position on value creation and how a lot of M&A, as we see it, is flying a little too close to the ground. So the market has, in our viewpoint, been pretty aggressive. Market pricing has been fairly leaned forward. We've also said we've been active in that marketplace. We've taken shots on goal, and we don't have any regrets. So I'm going to answer a question you didn't ask is what would cause us to stretch? Well, if we saw something that we could really build a new focus area on, if it were a place that had really high-quality rock, in an area we felt very comfortable from an operating environment that we could do what we do best in terms of build a capital-efficient program and if it could become another focus area of ours, we would consider stretching. But that's very theoretical. I just want to give you an idea of how we think. If it's just -- if it's an asset that doesn't really do anything for us, and we'd have to stick our neck out, we'd probably say no, that's not going to fit our pistol.

We'll move next to Charles Meade at Johnson Rice.

Yes. Tom, Shane and Blake and the rest of Coterra team there. Blake, I want to go back -- I believe it was your comments talking about how you're managing the Marcellus, and I want to explore that a little bit more as a way to try to understand a bit better how you guys are going to approach the optionality you have for more gas volumes or more gas activity. When I look at your 3Q results, it looks -- at least on the surface, it seems a little bit at odds to have 7 TILs in 3Q. But then you go back into a curtailment. But I think an earlier questioner said maybe you brought those online just to dewater and shut them back in. Can you tell us how -- and I know you made the point that you look at it on a month-to-month basis, but the sequencing of how you would -- whether it's TILs, rigs, completion crews about how you would exercise your optionality if you chose to?

Yes. Look, curtailments make TIL math hard, I get that. It's the -- this is all operationally driven. We need to dewater new wells. And so we won't hold those back to be part of our curtailment. As I have said, we look at every molecule once the capital has been sunk in the ground the same. And so we're managing these curtailments on a field level month-to-month. And that will include pinching back some new wells. It will include shutting in base production. So how would we respond to an increased gas market? Obviously, the first is through curtailment. Lifting curtailments would be the first. We have some really great compression programs we can speed up really quick to increase production. That would be another way. And then getting back after D&C. And we have shovel-ready projects ready to go, identified. The team is waiting for the phone call. So if we see those signals, we'll cut them loose, and we'll be able to respond. But I think it's really important, as Tom has said multiple times, we're willing to miss the front end of the return to not fully participate in the down cycle. And that's really what we're doing right now.

Got it. That is helpful, particularly the compression projects. And then the follow-up, going back to the Delaware, and you guys seem pretty pleased with your Lea County Bone Spring's results. And I'm curious, can you give us a sense of the size of the row projects that you would choose to there versus your 57-well Windham Row project that you're working on right now?

Yes. The -- I wish we could duplicate Windham Row across the Delaware Basin. It's really unique to Culberson County. That's our joint development area with Chevron, where together, we control 4 contiguous townships. We own all the infrastructure and midstream. We have complete flexibility to operate at will, and that's how we're able to capitalize on those efficiencies. So the row is really unique to Culberson. I will say in New Mexico, because of all the stacked pay we have and all the benches, we can really maximize wells per pad. We can still get some great efficiencies on co-mingling and just sharing infrastructure. So it's a little more of a vertical row than it is a horizontal row, but we're seeing a lot of efficiencies just going back and prosecuting benches, frankly, in developments we've been after now for almost a decade.

And our next question comes from Paul Cheng at Scotiabank.

I have 3. I just want to clarify a little bit. When you're talking about the LNG sales contracts, do you have the flexibility that not delivering your own physical molecule and instead buy from the market and just ship it or that the contract is a physical sales and so you don't have that flexibility?

Yes. Unfortunately, Paul, I can't give that kind of color on these deals, you know. I just echo again, these are netback sales deals directly tied to the foreign indexes we've listed.

Okay. And that for Waha, just curious that what you guys think, will Matterhorn be sufficient to really get the Waha gas price normalized? I mean, we -- even after the startup, we still see Waha gas pricing in the red. So just curious that, I mean, what do you guys have in mind?

I think it will help for sure, but it's by no means the final solution for Waha. The gas growth in the Permian is separating from oil growth. We are seeing higher gas growth year after year. You're seeing new projects already being announced and moving forward. And so growing gas is going to continue to be a concern for Waha, and we're really focused on just how we manage our Permian portfolio and looking at all options to improve pricing there.

Next, we'll move to Greta Drefke at Goldman Sachs.

I was just wondering, do you see any opportunities for smaller acreage additions that can help further increase average lateral lengths across your portfolio? And how are you thinking about the outlook for cost per foot improvement on that front?

Yes. Greta, this is Blake. Yes, we see opportunities for smaller acreage additions. Frankly, like in the Permian, our team there does this all day every day. There's lots of blocking and tackling that goes on within the basin. It's pretty much done in the form of trades. Really, acreage is the currency of the realm in the Delaware Basin, and you have to have some to participate, but we're constantly blocking up to get longer lateral lengths. We've put out our go-forward cost per foot that we see as it is today going into if we had to AFE all these programs right now based on our current cost efficiencies and our current market rates.

That's really helpful. And then for my next question, I was just wondering if you could speak a bit to your view on the call for natural gas from increased power demand over time. I guess, what are your latest thoughts on the incremental activity required from producers to meet this demand?

Greta, yes, Shane here. Look, I'll take that, and it's probably a variety of opinions in the room on that. But -- we see that as a big driver, a big call on gas as we look through the rest of this decade. When it comes and exactly how big it is, the materials that we look at, the conversations that we have and study, there's a bit of a wide berth of where that could ultimately end up. But I think there is a feeling that there's probably in the 30% to 40% to maybe a little greater than 40% of that incremental power demand could ultimately come from natural gas-fired power. And it's going to have to be something like that that's got that kind of reliability and dispatchability. So we're really excited about it. We can't wait to see it materialize and that manifests itself into gas prices.

Yes. We study this as well as anybody can, and we try to look at viewpoints that don't have economic or ideological investment in the outcome. And I might quote a slightly higher number than Shane in terms of the amount of the incremental power demand that must come from natural gas. There's no other solution in the timeframe in which this power will be required and the reliability that will be required for this power. There's no solution available other than natural gas for the bulk of it. So even if you're at the low end of the projection, it will be very, very constructive for natural gas demand. And we don't need much incremental demand to clear supply.

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

Well, I just want to thank everybody for your interest, your questions and your support of Coterra. We intend to continue our operational cadence, hopefully come to the market with clear and transparent communication of our long-term strategy and continue to be top-tier returns in all aspects. So thank you very much.

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