Good morning. My name is Audra, and I will be your conference operator today. I would like to welcome everyone to the Coterra Energy Third Quarter 2024 Earnings Conference Call. Today's conference is being recorded. All lines have been muted to prevent background noise. I would now like to turn the conference over to Dan Guffey, Vice President of Finance, Investor Relations and Treasurer. Please proceed.

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 will 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 in 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. 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 three 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 MBoepd per day, with oil averaging 112.3 MBo per day and natural gas averaging 2.68 Bcf per day. All three came in slightly above the high end of guidance, driven by the timing of operated and non-operated volumes as well as from 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 five net wells in our liquids-rich up-dip area, while in the Marcellus we brought online seven 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 costs 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 a 0.3 times 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 MBoepd, oil to be between 106 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 the product of a combination of timing during the fourth quarter, completing a portion of the Windham Row that was not simul-fracked 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, maintain the optionality to respond to signals on a month-to-month basis. Regarding investment, we expect total capital expenditures during 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 MBoepd 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 where 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 and 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.

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 two years of work by our marketing team to survey the LNG landscape and find deals that best enhance our portfolio. These commitments are net back 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 a 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 eight drilling rigs and two 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 am 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 two first Bone Spring wells at four wells per section and are seeing initial per well results comparable to the Upper Wolf Camp. 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 $1200 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 $10.50 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 includes drilling, completion, facilities and flow back. 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 cost 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 five years and today almost 60% of our Permian oil production is flowing through tankless facilities. Innovations like this are part of our unwavering standard 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 zero drilling or fracking activity. Going to zero 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 fracking activity. This thoughtful water strategy is what has allowed us to obtain the full capital flexibility we prize 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 one 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 one rig and completed five 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 three 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 great momentum behind us and with that, we'd be delighted to take your questions.

Thank you. We'll take our first question from Doug Leggate at Wolfe Research.

Thank you, good morning, everyone. Gosh, Tom, your prepared remarks, it was quite intriguing to hear you say if we decided to continue with simul-frac, our capital efficiency will improve materially in 2025, just boots 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 oil 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 the call today, which we do not, but if we had to make the call today, that's what we do. We have the program teed up, ready to go and we're just going to really like to maintain flexibility up until that point where we have to make a rock solid commitment and steer the ship.

I guess it's a tricky, a tricky follow up question. If I may then, Tom, which is really this, 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 three year plan, I guess you'll roll out early 2025 again. It seems to us that you've got a lot of options to perhaps drop the capital, maintain the original guidance. 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 three assets? Because it seems to me your optionality has probably never been better at this point.

Well, yes, Doug, I'm going to just repeat what you've heard us say. First thing we do, top line is make an estimate of what our cash flow will be given, a 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 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 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 the Cronin 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 and 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.

Okay, tricky one to answer, Tom. I'll leave it there, but thank you. Thank you for giving a good feeling. Thank you.

We'll move next to Arun Jayaram at JPMorgan.

Yes, good morning, 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. Depends where you are. But that, 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 plus, plus A plus 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 risks 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 situation and potential risks to Coterra if you see them.

Yes, I mean, in a nutshell, I think that story was very overblown. There's always legislative studies, there's always committee discussions going on. We don't expect the setback issues that were in the media a 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 three or four months and some of the proposals that have been made in the national media, in the political campaign. And we all know it's just talk. We don't think that the setback rule is a serious risk to our industry at this time.

Thanks, Tom. I'll turn it back next.

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

Hi, good morning, Tom and team. Thanks for taking my questions. 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 2025 and beyond?

Yes, I'm going to turn it over to Blake, but I want to make one comment before Blake jumps in. Part of our outperformance on all volumes is because of our efficiency of operations. And one of the things that 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 that 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 backs on all these things and that's really how we ground truth our results. If I really had to take 2024 and look at it in a nutshell, the date, I'd say about two thirds 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 third. 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 2025.

Then 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 two. 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 really skewed that and weighted it to that two-third, one-third that Blake talks about in terms of outperformance in 2024.

Great, thanks. Thanks for all the detail, guys. And I'm going to stick with costs and efficiencies. Imagine it will happen more as the call goes on. 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 road development. So 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, about $30 million a year, give or take. It would cost us to not 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. 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 forecasted costs go forward in Culberson. If we chose to pursue that type of program, we've laid out other road developments we see coming. You would see that cost being repeated over and over. And so that's really the tie between those two things. As far as, what if we went back to zipper fracking and Culberson? What could that look like? We'd 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.

Great. Thanks for the detail, guys.

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

Hi, Morning all. Thanks for the time, guys. My first question is on your Anadarko Basin specifically. Would you say that any of your future plans there, maybe next year after, are at all limited by the total lease position? If so, would you all consider 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 shield return, 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 shareholder returns in aggregate is starting with the base of 50% plus so that we hold dear. Above and beyond that, as we think about buybacks, there's really two things. What are the other options outside of buyback? And with regard to the buyback, I think we've talked about focusing on three 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 does the free cash flow profile look like not just in that quarter but really over the next three or four 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. 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 half a billion dollar area.

That makes sense. Thanks, Shane.

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

Sorry about that, was on mute. Good morning, guys. Thanks for getting me on. My first question is on capital efficiency slide 19. It's a nice one. That shows a breakdown of the row savings and the frac operations are a big part of that. The leading edge however is simul-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?

That's a great question, Kalei. We examine everything thoroughly and are not hesitant about simul-frac. As mentioned previously, most of our assets in the Delaware Basin are quite deep and involve high pumping pressures. It's essential to balance simul-frac while being aware of projected downtime and cost savings; otherwise, it might seem like you're saving money, but you could end up spending more by just accelerating the process. We continuously assess these factors. We believe we have a strong position with simul-frac in Culberson County, and we have proven the cost savings and understand what's achievable moving forward. However, we will always consider any approach that could genuinely reduce expenses.

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

Yes. In Culberson and Lea 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.

Thanks, again. My second question is about LNG. Our understanding is that your new contract or 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 cost 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 share more details with you. We have shared as much as we can about these deals. At a high level, these involve physical gas sales that are directly connected from our wellhead to foreign indexes. Each deal has a unique path to achieve this. Our main goal was to minimize variability, so we are closely aligned with these foreign indexes. We have successfully accomplished this in all our deals, making them genuine netback sales agreements.

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. I thought I'd 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. Just curious about your updated thoughts on hedging in the current environment.

Yes, absolutely. 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 a 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 volume. 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.

I appreciate the color. Thank you.

We'll go next to Matt Portillo at TPH.

Good morning, Tom and team. I have two overall questions. First, regarding the Permian. In the third quarter, you experienced significant gas volume growth compared to the previous quarter. I would like to know more about the factors driving that growth. Additionally, as we look ahead with Matterhorn going live, do you anticipate any further increase in gas production in the upcoming quarters, or have you faced minimal gas limitations so far this year due to your flow assurance?

Yes, Matt, this is Blake. I’ll address that. In the Permian for Q3, the main point is that we saw some unexpected improvements in gas-to-oil ratios, along with stronger gas production from certain wells than we anticipated. There haven't been any significant operational issues. Regarding flow assurance and the Matterhorn coming online, we’ve maintained our flow assurance throughout this period, which is our top priority for the marketing team. We focus on the volume first and prices second, so there hasn’t been any concern about flow assurance. However, we do have a portion of our portfolio that is tied to Waha, and we would be pleased to see any amount above zero.

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 endemic, 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 2025, 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?

First, yes, we are opening the wells to dewater them, which is part of our strategy. It's important to note that once we've drilled and completed the wells, the capital expenditure is the same for every gas molecule in the Marcellus. We manage curtailment across the field in the most cost-effective way without differentiating between new and existing wells. We will dewater them, and as mentioned earlier, we're making decisions on curtailments on a month-to-month basis as our Northeast exposure fluctuates. Regarding rig to volume, we have on-ramps and off-ramps in our capital program. We have on-ramps in the Marcellus, so if gas prices respond positively, we will be ready to take advantage of that.

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 2024, which is certainly a nice trend to see and your volumes have gone up. So I know you have 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, the efficiencies we are realizing are repeatable, and we incorporate them as we progress. If we were to update that same 3-year guidance today, it would appear more favorable. However, the outcome is significantly influenced by our decisions for 2025, and we are not prepared to share any details on 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 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 two points and draw a straight line in the future.

Okay. That's helpful to 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. Regarding the Mid-Con deal, we would consider a smart bolt-on. To address your question broadly, we are cautious about value creation, as much of the M&A activity we've observed seems somewhat risky. The market appears to be quite aggressive, with pricing moving forward quickly. We have been active in exploring opportunities and have taken our chances without regrets. Now, to answer a question you didn’t ask about what would prompt us to stretch: if we encounter an opportunity that allows us to establish a new focus area on high-quality resources in a comfortable operating environment, we would be open to stretching. However, that’s a theoretical scenario. If we find an asset that doesn’t significantly add value and requires us to take unnecessary risks, we would likely pass on it.

Okay, thank you for the thorough response.

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

Good morning Tom, Shane, Blake, and everyone at Coterra. Blake, I want to revisit your comments about managing the Marcellus and delve deeper into how you'll approach the flexibility you have for increasing gas volumes or activities. Looking at your third-quarter results, it seems somewhat inconsistent to see seven TILs while also entering a curtailment phase. An earlier question hinted that you might have brought those online temporarily. Can you elaborate on how you manage the sequencing of TILs, rigs, and completion crews in terms of exercising that flexibility if you decide to?

Yes. Curtailments complicate the calculations, and I understand that. This is all driven by operations. We need to dewater new wells, and we won't hold those back for curtailment. We evaluate every molecule equally once the capital has been invested. We're managing curtailments on a monthly basis at the field level. This includes restricting some new wells and shutting in base production. In response to an increased gas market, our first action would be to lift curtailments. We have effective compression programs that can quickly ramp up production. Additionally, we have ready projects identified, and our team is prepared to move when we see the right signals. However, it's important to note, as Tom has mentioned several times, that we're willing to miss some initial returns to avoid fully engaging in the downturn. That's our current approach.

Got it. That is helpful, particularly the compression projects. Regarding Delaware, it seems you are quite pleased with the results from your Lea County Bone. I'm curious if you could provide some insight into the scale of the road projects you would consider there compared to your current 57 well Windham Row project.

Yes. I wish we could replicate Windham Row throughout the Delaware Basin. It’s truly unique to Culberson County, which is our joint development area with Chevron where we control four adjacent townships. We own all the infrastructure and midstream assets, giving us complete flexibility to operate as we choose, allowing us to take advantage of efficiencies. The roads in Culberson are particularly distinctive. In New Mexico, due to the stacked pay we have and the multiple benches, we can maximize the number of wells per pad. We can achieve significant efficiencies through co-mingling and shared infrastructure. While it's more vertical in nature than horizontal, we are noticing many efficiencies as we continue to develop benches that we have been pursuing for nearly a decade.

And our next question comes from Paul Cheng at Scotiabank.

Hi, good morning guys. 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 franchise is a sales and so you don't have that flexibility?

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

Okay. I'm curious what you think will be enough to normalize the Waha gas price. Even after the startup, we still see Waha gas pricing below expectations. What do you 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 Grant Drake at Goldman Sachs.

Hi, good morning and thanks for taking my question. 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? Thank you.

Yes, Grant, this is Blake. We see opportunities for smaller acreage additions. In the Permian, our team is actively working on this every day. There is a lot of ongoing activity within the Basin, primarily through trades. Acreage is essential in the Delaware Basin, and we continually work to secure more in order to extend our lateral lengths. We have shared our current cost per foot as it stands today, considering our efficiencies and market rates if we were to proceed with all these programs right now.

Thank you. 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 selectivity required from producers to meet this demand?

Shane here. I'll address that and recognize that there are likely differing opinions on this. We view natural gas as a significant factor in the energy landscape for the remainder of this decade. While there's uncertainty about the timing and magnitude of this demand, our analysis and discussions suggest that around 30% to 40%—perhaps even slightly more—of the additional power demand will likely come from natural gas-fired plants. This transition depends on the reliability and flexibility that natural gas can provide. We're truly excited about these developments and look forward to seeing how they influence gas prices.

We analyze this as thoroughly as anyone and aim to consider perspectives that aren't influenced by economic or ideological biases. I may suggest a somewhat higher estimate than Shane regarding the incremental power demand that will need to be fulfilled by natural gas. There is no alternative solution within the required timeframe and reliability for this power; natural gas is the best option for most of it. Even at the lower end of the projection, this will be very beneficial for natural gas demand, and we do not require much additional demand to balance supply.

Thank you.

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.