Thank you, Greg. Good morning, and thank you for joining Coterra Energy's Third Quarter 2025 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 Michael Deshazer, Executive Vice President of Operations. Blake Sirgo, Executive Vice President of Business Units, is also in the room to answer questions. Following our prepared remarks, we will take your questions during our Q&A session. As a reminder, on today's call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures were 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 good morning to everyone listening. Coterra had a strong third quarter and is positioned to meet the ambitious goals we set for 2025. We also shared a preliminary overview of our upcoming 3-year plan update, reaffirming our commitment to consistent, profitable growth and value creation for our shareholders. I'd like to recognize our field and office teams for their hard work in delivering results safely and responsibly while also maximizing full-cycle returns. We are incredibly proud of their dedication to excellence. In the third quarter, we exceeded our guidance for gas, oil, and barrel of oil equivalent volumes, achieving impressive returns on invested capital and demonstrating strong capital efficiency. The integration of the Lea County assets acquired earlier this year has progressed well, resulting in significant improvements in performance, cost savings, and future inventory. Michael Deshazer will elaborate on this shortly. We plan to present a comprehensive 3-year outlook with our fourth quarter release in February. In the meantime, we provided early insights into 2026, highlighting our commitment to increasing revenue, cash flow, free cash flow, and profitability. We anticipate moderate year-over-year capital spending while maintaining steady, profitable growth. Our competitive breakevens and extensive inventory, along with balanced revenue from both gas and oil assets, position us well to deliver consistent results. We are focused on enhancing shareholder value by making prudent investments throughout commodity price fluctuations. I want to note that our guidance for 2026 is preliminary, as we are closely monitoring market conditions. The oil markets are complex, influenced by factors such as Russian sanctions, the situation in Venezuela, and economic conditions in China and India. Although we have the capacity to boost oil growth if necessary, we are committed to a disciplined approach in the current market environment. Our primary focus remains on sustainably growing profitability and maximizing free cash flow. Amid shifting conditions, increasing LNG exports and rising electricity demand create a positive outlook for natural gas in the medium and long term. We are prepared to exercise patience and avoid prematurely reacting to demand increases. Our marketing team is actively engaging with counterparties to secure new natural gas supply agreements, further diversifying our already strong portfolio, which includes significant commitments to recently announced LNG projects and local power plants. While these agreements comprise around 30% of Coterra's gas production, the team continues to explore innovative strategies to enhance and diversify our offerings. Our marketing group is driven to create value rather than to generate publicity. We believe that with patience, the future of natural gas will present substantial opportunities for Coterra. There is much more happening behind the scenes. We are monitoring all markets closely, as sentiment can shift dramatically with minor changes in the facts. Coterra has a robust inventory of oil assets characterized by one of the lowest breakeven points in our sector. Our strategy is to maintain a steady course without reacting wildly to market fluctuations. Before handing the call over to Shane, I want to mention that Michael Deshazer will provide today's operational summary. Blake Sirgo is also with us and will likely share some comments. We recently realigned the roles of Blake and Michael, with Blake overseeing our business units and Michael taking on operational and marketing responsibilities. This change aims to enhance our team's expertise and ensure broad familiarity with all areas of our business. Such adjustments increase our adaptability, offer fresh perspectives on key issues, and allow both Michael and Blake to expand their contributions. Lastly, we are aware that Kimmeridge released a letter this morning. While we believe it contains some inaccuracies, we respect the valuable insights the Kimmeridge team has offered over the years and have engaged constructively with them in the past. We are disappointed they chose to release a public letter without reaching out to us first. Nonetheless, we welcome constructive feedback and will thoughtfully consider any suggestions that could enhance Coterra. Now, I will pass the call to Shane for a financial summary.

Thank you, Tom, and thank you, everyone, for joining us on this morning's call. Today, I'd like to cover three topics. First, I will quickly summarize a few key takeaways from our strong third quarter financial results. Then I'll provide our fourth quarter guidance and update to our full-year 2025 guidance. Finally, I'll provide comments on our balance sheet and cash flow priorities for the remainder of the year. Turning to our performance during the quarter. Performance in all three business units exceeded expectations during the third quarter. Coterra's oil, natural gas and BOE production each came in approximately 2.5% above the midpoint of our guidance. Additionally, NGL production was strong, posting an all-time high for Coterra at around 136 MBoe per day. In the Permian, we had 38 net turn-in-lines during the quarter, just below the low end of our guidance range, while the Anadarko and Marcellus had net turn-in-lines of six and four respectively, in line with expectations. We continue to expect TILs in all areas to be within our annual guidance ranges with the Permian being near the high end of the range. Pre-hedge oil and gas revenues came in at $1.7 billion with 57% of revenues coming from oil production. This is up sequentially from 52% in the prior quarter and was driven by a substantial uptick in oil volumes of 11,300 barrels per day, an increase of above 7% above our second-quarter levels. The Permian team continues to drive outstanding incremental production results. Cash operating costs totaled $9.81 per BOE, up 5% quarter-over-quarter due to production mix and higher workover activity, which we expect to moderate during the fourth quarter. Incurred capital in the third quarter were near the midpoint at $658 million. Discretionary cash flow for the quarter was $1.15 billion and free cash flow was $533 million after cash capital expenditures. Both of these figures benefited from negative current taxes for the quarter related to recent changes in U.S. tax law. In summary, our strong third quarter results show continued improvement in capital efficiency as production exceeded expectations and capital remains on track. We continue to run a consistent and highly efficient activity cadence, which we expect will continue to generate strong full-cycle returns in the current price environment. Looking ahead to the fourth quarter and the full year 2025. During the fourth quarter of 2025, oil production is expected to be 175 MBoe per day at the midpoint, an increase of over 8,000 barrels per day or another 5% increase quarter-over-quarter. We expect total production to average between 770 and 810 MBoe per day and natural gas to be between 2.78 and 2.93 Bcf per day. We expect capital for the quarter to be around $530 million, significantly below the third quarter results as we wrapped up frac activity in the Anadarko late in the third quarter. For full year 2025, we are increasing annual MBoe per day production guidance to 777 at the midpoint, a 5% increase from our initial guidance in February. We are maintaining the oil guidance midpoint at 160 MBoe per day while tightening the guidance range. Oil volumes from our acquired assets have been in line to slightly better than expected. Our legacy assets oil volumes are expected to deliver a high single-digit percentage growth rate year-over-year. This is similar to the rate of growth we have delivered during the prior three years. On natural gas, we are increasing the midpoint of our volume range to 2.95 Bcf per day, an increase of over 6% from our initial full-year guidance in February. As previously indicated, we expect capital for the year to be approximately $2.3 billion, just above the midpoint of our initial guidance range in February as we have maintained the second Marcellus rig into the second half of the year. Our annual expense guidance ranges remain unchanged, and we expect to be near the midpoint of the aggregate expense range for the full year. With regard to our 3-year outlook provided in February, we remain highly confident in our ability to deliver results within those ranges from 2025 through 2027. This outlook is underpinned with a low reinvestment rate and improving capital efficiency and delivers attractive long-term value creation for our shareholders. While we are not prepared to provide specific 2026 guidance, a current snapshot suggests that capital should be down modestly year-over-year while still maintaining production parameters laid out in our 3-year guide we released in February. At the same time, our low breakevens, low leverage and operational flexibility, coupled with our hedge book, have Coterra well positioned in the event of high commodity price volatility in 2026. Turning to shareholder returns and the balance sheet. For the third quarter, we announced a dividend of $0.22 per share. This is one of the highest-yielding dividends in the industry at over 3.5% and demonstrates our confidence in the long-term durability, depth and quality of our future inventory and free cash flow. Additionally, during the third quarter, we repaid $250 million of outstanding term loans that were used as part of the financing of our acquisitions earlier this year, bringing our total term loan pay down to $600 million through the third quarter of 2025. In October, based on the progress we have made in retiring our term loans and the trading levels of our shares, we reinitiated our share buyback program. While we continue to make progress on our debt retirement goals during the fourth quarter, we'll be opportunistic in purchasing our shares. We ended the quarter with an undrawn $2 billion credit facility and a cash balance of $98 million for total liquidity of $2.1 billion. As of September 30, we had total debt outstanding of $3.9 billion, down from $4.5 billion at the closing of the acquisitions in January. We're making meaningful progress in executing on our priority of getting our leverage back to around 0.5x net debt to EBITDA. Coterra remains committed to maintaining a top-tier fortress balance sheet that is strong in all phases of the commodity cycle. We believe this enables us to take advantage of market opportunities while protecting our shareholder return goals. In summary, Coterra's team delivered another quarter of high-quality results across all three business units. We continue to enhance capital efficiency through higher productivity and lower cost per foot completed. Our consistent activity has continued to deliver meaningful oil production growth throughout the year while raising the bar on both natural gas and BOE production. In 2025, we expect to generate substantial free cash flow of around $2 billion, an approximately 60% increase over 2024, benefiting from both higher natural gas realizations and higher oil volumes from our acquired assets. While we continue to prioritize deleveraging, we see significant value in Coterra at current share prices and are approaching buybacks opportunistically. In summary, Coterra has never been stronger or better positioned. With that, I will hand the call over to Michael to provide additional color and detail on our operations.

Thank you, Shane. Today, I will discuss our operational results and outlook for the third quarter. We'll give an update on our business units, including the successful integration and benefits of our Franklin Mountain and Avant acquisitions, and I will briefly cover our marketing efforts. The third quarter went smoothly, and we are carrying this operational momentum into the fourth quarter. We currently have a consistent program with 9 rigs and 3 crews working in the Permian, 1 rig and crew in the Marcellus, and 1 rig in the Anadarko. We plan to maintain this level of activity during the fourth quarter. Looking ahead to 2026, we expect a modest year-over-year decrease in capital, while still achieving the production targets outlined in our three-year outlook for 2025 to 2027. We are focused on consistent operations through commodity cycles, maintaining maximum operational flexibility without long-term contracts for rigs or frac crews. We intend to provide detailed 2026 guidance and update our three-year outlook in February. The integration of the Franklin Mountain and Avant assets is complete, and our teams are exceeding our synergy expectations. I want to highlight our progress. Upon announcing the acquisition, we estimated the productivity of many wells in various development stages for our evaluation and annual production guidance. In November 2024, we projected a 2025 production estimate of 40,000 to 50,000 barrels of oil per day from these assets, assuming a full year’s contribution. After updating our production guidance following the actual closing of the assets in late January, we held on to our annual production forecasts due to the strong performance of the assets. I am pleased to report that we continue to exceed our production expectations for the acquired assets, reinforcing our confidence in their potential beyond the acquisition assumptions. On the capital side, we've achieved a 10% reduction in well costs per foot by implementing our best practices across these assets. Some efficiencies include optimized and standardized hole sizes and casing designs, which have decreased our drilling times from 15 to 13 days for a standard 2-mile lateral. In terms of completion, using our proven stimulation designs tailored for each landing zone and scaled in the Permian has lowered service costs. Beyond capital savings, we see potential for significant operating cost synergies. We have already cut the inherited lease operating expense by about 5%, equating to approximately $8 million per year. This reduction applies to most services, but the largest savings come from on-pad sour gas treatment and electric generation. For instance, at our Eagle central tank battery, we integrated a facility that treated sour gas for power generation. By facilitating a residue gas connection, we eliminated the need for gas-treating equipment, enabling the turbines to use cleaner low Btu gas, which enhanced reliability and saved over $2.5 million annually in expenses. We anticipate an additional $20 million per year in net operating cost savings related to sour treatment, projecting a total of 15% in operating expense savings for the acquired assets moving forward. We believe that future savings may arise from employing microgrids instead of well-site generators to power our assets. We are finalizing plans for up to three microgrids in our Northern Delaware Basin assets. These projects could potentially cut our current power costs by 50%, resulting in an additional annual savings of $25 million, with projected savings growing to nearly $50 million as our asset and power demand increase. Meanwhile, we are collaborating with utility power providers to enhance grid power availability in the Permian Basin. With our assets now fully integrated, we expect to demonstrate reductions in capital and expenses, alongside productivity improvements as we focus on capital efficiency in our development plans. Our subsurface teams have identified multiple landing zones, providing confidence that we have 10% more inventory than initially estimated during the acquisition based on net lateral footage. Additionally, our expanded scale in the Northern Delaware Basin has allowed us to engage in numerous value-enhancing trades and smaller acquisitions. We plan to prudently add valuable inventory as we continue to develop our profitable, low-cost resources in the Permian Basin. Moving on to the Marcellus business unit, this quarter we drilled a new 4-mile lateral from spud to rig release in under nine days, averaging 2,400 feet per day, setting a new record for Coterra. Recently, it's become common for many of our new wells to exceed 2,000 feet per day. This performance, along with longer laterals over 20,000 feet, has decreased drilling costs by 24% year-over-year. With these efficiencies, we no longer require two rigs to maintain production in our Marcellus assets. Our maintenance activity level over the coming years will require one to two rigs, so we will manage our rig count to avoid excessive DUC backlog. While we can increase our Marcellus natural gas volumes, we remain patient and aim to keep production levels steady until additional demand emerges and the market stabilizes. If we experience a cold winter and prices rise in 2026, we will fully leverage our approximately 2 Bcf a day production in the Northeast and expect to generate substantial free cash flow from the Marcellus region. In the Anadarko unit, we successfully brought online our last project of the year in the third quarter, the five 3-mile Hufnagel wells. These new wells, along with our Roberts project from Q2, are contributing to strong regional performance that has exceeded our expectations. Turning to marketing, our team continues to seek out deals and partnerships that can ensure flow assurance and improve price positioning for our products across our various portfolios. As Blake noted last quarter, our long-term gas sales to CPV's new Basin Ranch power plant in Reeves County, Texas, is the latest in a series of successful transactions. As Tom mentioned, our Moxie and Lackawanna power agreements in the Marcellus were established a decade ago and have consistently delivered value well above the local price. We will continue to pursue opportunities to enhance the margins of our products and increase shareholder value. The diversity of our sales portfolio is a key strength, but we are not complacent and will keep optimizing. Our teams across all three regions are performing exceptionally and are focused on effective execution, making decisions to maximize full-cycle returns and create shareholder value. With that, I will hand the call back over to the operator for Q&A.

It looks like our first question today comes from Doug Leggate with Wolfe Research.

Tom, thank you for addressing the comments regarding the Kimmeridge letter. Could you share your thoughts this morning? It seems that when you compare your performance to other gas-levered E&Ps, especially larger peers like EQT and Expand, your portfolio mix makes it feel like you've been somewhat isolated. The Kimmeridge letter suggests that you would be more successful as a standalone pure play in the Delaware while allowing someone else to manage the gas aspect. This seems to contradict your original vision. How do you view this?

Well, first off, Doug, I don't want to get into a lot of discussion about the Kimmeridge letter. That's for another time. But we've spoken openly. We really believe Coterra is a premier outfit, and we would like to see us trade at a premium multiple. However, if you look at the trading over the last year, you'll find that we are at the top of the stack of oil companies and at a lower level of gas companies. We think we're seeing benefits from being a multi-basin, multi-commodity company. But I just believe it would be inappropriate for me to elaborate further, Doug.

Okay. I understand, and I appreciate you taking a stab at it. My follow-up is an operational question, and it's really related to what you saw in your LOE this quarter. Obviously, it's still elevated, but you also beat on your oil guidance. So my question is, is this related to the workovers in the Harkey? Should we continue to expect your oil production to move up and then ultimately your LOE to move down as those workovers flow through the system?

Yes, Doug, this is Michael. Yes, the LOE for the quarter was up a little bit. We have transitioned out of the Harkey remediation program that we talked about last quarter, and we have moved workover rigs into Lea County, where we do have some higher working interest. But overall, we do expect our LOE costs, especially the workover costs to decrease as we head into Q4.

Yes. Doug, this is Shane. We expect that number to stabilize for the year within the range on the LOE and anticipate being around the midpoint for total cash costs. Michael explained well why it appeared to be higher in the third quarter.

And our next questions come from the line of Betty Jiang with Barclays.

I want to ask about the cash return strategy just because we would agree that the stock, it does look discounted in our view as well. Shane, last quarter, you talked about really focusing on debt reduction. And then this quarter, Coterra is starting the buyback program again. How do you think about the allocation of your excess free cash flow between debt reduction and buyback going forward? Is there a reason not to think we can get back to that 100% return level into next year?

Yes, Betty, Shane here. Thanks for the question. As you mentioned, year-to-date, we have focused on reducing our debt by paying off term loans, which is why we were particularly aggressive in the third quarter. It's interesting that as we approach the final stages of repayment, our mindset shifts compared to the beginning phases. This makes it easier to balance between buyback activity and further debt reduction. As we discussed, we restarted the buyback program last month and plan to be opportunistic, especially given price trends over the last month and a half. Looking ahead, I can only refer to our history; in 2024, we returned about 94% of our free cash flow through dividends and buybacks. The prior year, we were around 75%. That's the target we aim to get back to, and we believe we're progressing well toward that goal. While we can't specify exactly what it will look like in 2026, we anticipate having a strong capital return program in place then.

That's great. My follow-up is on the overall activity in the Permian. When comparing the Delaware to your initial expectations, production guidance remains unchanged, while you are now completing wells towards the upper end of the guidance range. I'm curious, relative to your internal expectations, how does the production profile of the wells compare to your initial guide? With activity now leaning towards the high end, does that alter your perspective on the shape of 2026?

Betty, Shane here. I'll address that. We typically do not comment on the timing of TILs within specific quarters, but we do provide the expected number of TILs for each quarter. You'll see that in the third and second quarters, we were at the lower end of what we anticipated, which caused some activities to shift into the fourth quarter. However, the productivity from the TILs that have started up has generally met expectations and, in some cases, performed slightly better. Looking ahead to next year, Tom mentioned on the last call that we would finish the year at 175 MBoe in the fourth quarter. It’s important to note that we may not maintain that level consistently. Historically, due to the timing of TILs, we might experience a slight dip before starting to increase again.

Yes, Betty, I would just add to that, that so much of this is timing, as Shane said, and working interest changes. So there's just a lot of moving parts. But we're seeing very, very solid returns and performance out of all of our assets, and particularly in the new assets we acquired earlier this year, they're coming on strong. There's just no question in our mind as we reflect back on the last year, we'll exit the year a much stronger company than we entered the year. And we were able to do that because of our balanced portfolio, our multi-revenue contribution to that balance and our strong and fortress balance sheet. So we're absolutely exiting the year a stronger, better company.

And our next question comes from Arun Jayaram with JPMorgan.

Yes. Team, I wanted to see if you could provide any kind of overall commentary on your thoughts on CapEx reduction next year. You mentioned that you think it will be down moderately, but maybe help us fill in the pieces of the drivers of that, perhaps relative to your soft guide of delivering 5% year-over-year oil growth.

Yes, Arun, I'll begin, and others may want to add their insights. We are observing strong asset performance. As we look toward the oil markets, we are paying attention to upcoming developments. Overall, one can view the market positively, although some of this is influenced by cartel discipline and geopolitical issues. If we take a step back, we recognize that the world is relatively oversupplied if all producers operate at full capacity. Therefore, we aim to be cautious. Our ability to reduce capital expenditures is linked to our asset performance, and we are on track to meet our three-year plan comfortably. We do have the potential to increase capital and accelerate oil growth, as mentioned in my initial comments. However, our focus is more on cash flow and profitability rather than just volumes. The most effective way to enhance cash flow and free cash flow, when there is price support for your commodity, is to achieve some volume growth. We are monitoring the markets carefully.

Yes, Arun, I mean the only thing I would say is, in addition to that is, look, nothing's set in 2026 yet. We've got a lot of flexibility as we see it today. We'd be modestly down. But I think you're going to see us when we come out in February, deliver a highly capital-efficient plan that generates a substantial amount of free cash flow. As I noted in my earlier comments, cash flow this year was up 60% over 2023 on the back of higher oil volumes from the acquired assets as well as higher natural gas price realizations. The two of those contributed, and it's a really powerful combination.

Got it. And then maybe my follow-up, you highlighted some parts of the Franklin, Avant acquisitions that closed in 1Q, maybe exceeding your expectations. Can you talk about some of the things that you're seeing post your review of those acquisition economics and maybe a little bit more insights on the ground game that you've done. I think you're investing about $86 million in leasehold, which is driving a little bit more of an inventory improvement there.

Yes, Arun, this is Blake. Happy to take that one. Frankly, our teams have done what we hope they do. They've taken this asset, and they've made it a lot better. Our subsurface teams are delineating. So we're finding new zones that we didn't account for when we underwrote it, and we're adding net footage across the asset base. Our D&C teams are attacking the program with all of our large efficiencies we built over the years. We're driving down dollar per foot and our production and midstream teams are attacking OpEx, and they're dropping that as well. So we're really just seeing those efficiencies across the board. They're really starting to add up, and this is a great add to our portfolio.

Our next question comes from Neil Mehta with Goldman Sachs.

I have a couple of questions about gas, Tom. But first, to elaborate on your initial comments, one question we hear from investors, even beyond the letter this morning, is what the value is of operating as a multi-basin portfolio compared to being a pure play. Since it's been a couple of years since you included Cabot in your portfolio, could you provide some examples of the tangible benefits or synergies you've gained from diversification? Certainly, commodity value is one factor, but I’m sure there are others as well.

Yes, we need more time to address that question. Surprisingly, even within our broad industry, there are specific regional pockets, and many companies operate within a single basin. This leads to techniques and operational efficiencies being concentrated until they become widely adopted. Our history shows this repeatedly. For instance, the industry moved to plug-and-perf completions, yet some basins continued using slotted liners long after others had moved on. This trend is evident with various completion techniques. Speaking for Coterra, our recognition as a top operator in every basin we operate in stems from being a multi-basin company. We can apply best practices across different plays to enhance our programs. A specific example is our substantial progress in winterization in the Permian Basin, which we hope to demonstrate this upcoming winter. We gain insights from our competitors due to our interests in their wells. During winter storms, we observe how significantly our competitors' production drops, while Coterra remains largely unaffected. This resilience is a result of the collaboration between our Marcellus team, who regularly contend with severe winters, and our Permian team. This partnership has improved our operations and enhanced our ability to market products at winter pricing. The benefits of collaboration across different play types continue to expand our technical problem-solving capabilities, making our company stronger.

And then the follow-up is just on scale. I mean, I think in the Permian, Franklin Mountain continued to give you the scale that you need to be competitive against the largest players in places like the Permian. In the Marcellus, we've seen a lot of consolidation here. Do you feel like you have sufficient scale to be first quartile in the Northeast?

Yes, I believe we have the necessary scale. We produce about 2 billion cubic feet per day in the Northeast market, which is close to 11 billion. When we negotiate with service providers, it goes beyond just securing a single frac crew for that area. Having one active crew allows us to negotiate based on our broader portfolio, which helps us reduce costs, obtain better equipment, and gain more focused attention from service providers. Therefore, we have ample scale in the Northeast, and it benefits from Coterra's larger scale.

And our next question comes from Scott Gruber at Citigroup.

I want to come back to your active ground game here. Can you talk about your thoughts around running room to block up your positions in Lea and Eddy counties and the timing of doing so in a competitive market? And just how important is that in terms of compressing your cost structure in the Northern Delaware down towards Culberson? Or do you think you have kind of a good running room to further compress costs on your current acreage position?

Yes, Scott, this is Blake. I'll take that. The Franklin Mountain, Avant assets really gave us a great footprint in the Northern Delaware. And what that's allowed us to do is now have a foothold in certain areas where we can start doing trades and additional small acquisitions. And really, what we're just chasing are the biggest DSUs we can get our hands on, more wells per section, longer lateral lengths, that's how we drive efficiencies. And so really just building that footprint up there has kind of turbocharged our land efforts. And I couldn't be happier with the deals the team has brought in over the year. They're very, very busy. We look at all those with a firm economic lens. But like I said, those capital efficiencies we can bring to bear make a lot of them really attractive to us.

And what is your color on the '26 budget reflects the trend in well costs in the Northern Delaware as you gain more experience on the acreage and expand the position? Does that continue to step down? Would that be incremental benefit to the spend in '26? And does the well mix in the Delaware stay broadly the same in '26 kind of as you see it today?

Scott, this is Michael. As I mentioned earlier, we are actively working to reduce the capital costs associated with our wells in the Northern Delaware Basin. We anticipate that our teams will remain focused on this effort daily. While we don't have a specific forecast to share at this moment, I did highlight the efficiencies we are experiencing across our operations, such as using consistent drilling rigs and frac fleets, as well as drilling longer laterals. These advantages will also apply in the Northern Delaware Basin. Additionally, the larger pads and the strategic organization of our acreage, as Blake mentioned, significantly contribute to our ability to lower costs on production, capital, and midstream operations.

Our next question comes from David Deckelbaum with TD Bank.

I wanted to ask perhaps for a little bit more color just on the '26 high-level guide of spending kind of sub $2.3 billion. How the sort of large projects impact that going into next year? Or as we think about this, is it being driven more by reallocation between basins or the inclusion of more Wolfcamp relative to what we saw in '25? Could you add a little bit more color there just on what's contributing to that trajectory the most? Or is it just general optimization?

Thanks, David. This is Michael. As we discussed earlier, our operations are stable across the business units, and we anticipate this stability will continue into 2026. We don’t expect significant changes from our current position in Q4 regarding the program’s outlook for '26. I mentioned that our Marcellus operations will involve between one and two rigs, and we'll make decisions based on frac efficiency and drilling efficiency. We're excited about the recent results of drilling longer laterals in the Marcellus, which have allowed us to reduce the rig count. Our focus is not so much on the resources related to rig and frac, but rather on maintaining a consistent program within each of the business units from a capital perspective.

Yes, David, I want to just add there that I'll be a broken record, but it is a soft guide, not an announced plan. We're still looking at some of our options. I think depending on what happens with commodity markets, though, as we look at that soft guide, probably our bias would be to maybe slightly increase over what we're telegraphing than decrease. But we have the wherewithal, we have the projects, and we have the willingness to step in. We're just watching carefully, and we want to be prudent in how we approach 2026.

I appreciate that insight, Tom. To follow up on the timing of the program into 2026, you mentioned a 5% oil growth for next year. Michael, could you share your thoughts on how the Delaware may progress throughout the year following the strong growth we observed in the latter half of 2025?

Yes, we're not prepared to discuss any kind of TIL timing or that kind of granularity at this point in time.

And our next question comes from the line of Matt Portillo with TPH. Following up a bit on the cadence of the program into '26, you mentioned a 5% oil growth next year. Michael, can you provide insight on how the Delaware is expected to progress throughout the year after the aggressive growth we saw in the latter half of '25? Michael Deshazer, Executive Vice President of Operations, responded that they are not ready to discuss any specific timing or details at this time.

I wanted to start out on the power opportunity in the Permian. You mentioned the microgrids. That seems like a great opportunity for you all to cut costs moving forward. I was curious if you might be able to provide a little bit more color around the timing of when those microgrids might come into service and how many megawatts you're planning on deploying.

Yes, Matt, this is Michael. We currently have some smaller scale microgrids that we inherited with the Franklin Mountain, Avant acquisition. I discussed in the prepared remarks that Eagle's central tank battery has turbines located on it that are powering adjacent leaseholds. So we're already in this business, and we're really just looking for opportunities to expand it. As you know, the Northern Delaware Basin and really the Permian on the New Mexico side has been very constrained for power for some time. And many operators are using small reciprocal engines to generate power on a well site-by-well site basis. And where we see value is when we can connect multiple leases to a single permanent station that's run off turbines. We see a dramatic decrease in that electrical cost. So we're going to continue to expand the current microgrids that we have. And like I mentioned in the remarks, we see opportunities for about three expanded microgrids across our asset.

Great. And then maybe a follow-up on the Northeast. It sounds like the soft guide as it stands today at strip is for relatively flat volumes around that 2 Bcf a day. I just want to make sure I heard that correctly. But maybe over the medium term, I was hoping you might be able to comment on your updated thoughts around power demand growth regionally for Northeast PA? And then any updated thoughts on maybe some of the longer-haul infrastructure opportunities such as Constitution that had been discussed earlier in the year.

I'll start by addressing the second question regarding the Constitution project and some other initiatives in that region. Historically, this project has originated from our acreage and extends towards the Iroquois line, which is approximately 124 to 125 miles away. If anything were to arise regarding that project, we would naturally be a key partner. However, without clearer insights on potential markets, buyers, and commitments at the other end of the line, it’s likely that this project will face some challenges. There are certainly other projects in that area, like NeSSIE, which seem to be gaining more traction at this time. While we might not have a direct connection to NeSSIE, we anticipate benefiting from any development in the region. Sorry, regarding the first question...

Just around the regional power demand growth opportunity specific to Northeast PA, just how you see that market emerging and what that might mean maybe for the opportunity to add some volumes at some point in the future from a production standpoint?

Yes. That's great. So a lot of activity in PA, a lot of announced activity, that's preliminary, not necessarily all with definitive agreements, but with intention, which is a good first step. I think as well, there's a lot of unannounced activity that is up there right now in terms of dialogues that are going on. I think Michael and Tom sort of alluded to our team and being a part of those conversations. And so we're very excited about the potential up there, and we'll continue to work it hard. Some of these projects, whether we're involved or not, take a long period of time to develop and get announced. For example, again, not in the PA, but in West Texas, those are discussions that we have been in with CPV for the better part of 2 years. And so these are just long lead time discussions and negotiations that are ongoing, and we have a history of involvement in all of our business units, frankly, and I would expect we'll continue to be active in those dialogues.

Matt, we have significant flexibility in our marketing efforts in the Northeast and are closely monitoring the growth of these markets. We have discussed potential opportunities related to certain pipelines. Our marketing team has effectively established a weighted average sales price through various arrangements, including LNG, direct power, and sales to industrial users. When evaluating growth, we focus on the additional molecule relative to the additional price. Despite analyzing what some competitors are doing, we believe it is not the right time to increase volumes at this price point. We will exercise patience, as we anticipate opportunities will arise, and we are prepared to take advantage of them. We also have the chance to increase our volumes through enhanced activity and existing commitments that will provide us with more marketing flexibility in the future. Overall, we are in a solid position, and as I mentioned earlier, we believe that being patient and prudent is the best approach at this time.

And our next question comes from Kalei Akamine with Bank of America.

I want to start on the Marcellus. The deal with Cabot closed about four years ago, and you've made that position better through your operating efficiencies. So maybe you can start by calling out some key operating wins. And then when you look at the Marcellus landscape, do you think that the application of your best practices could create value through M&A?

Yes, Kalei, I'll address the first part. Shane will discuss M&A. We approached the Marcellus with great enthusiasm when we acquired the asset, as it offered us a clean slate in the Upper Marcellus to explore. With over ten years of experience in developing shale basins in Oklahoma, Texas, and New Mexico, we applied those same skills here. One of my favorite comparisons is between the inventory at the time of acquisition and what we have now; there has been a significant increase in lateral length across the asset. We optimized well spacing to boost productivity and improved the entire cost structure. When we began working on this asset four years ago, we relied heavily on trucking our frac water, but I'm pleased to report that we now pipe all our frac water. This has allowed us to significantly reduce costs overall. Many of the best practices Tom mentioned earlier have been adopted through hard work, and once we internalize these lessons, we spread them rapidly.

I have a follow-up question about the Marcellus inventory. I see that you're still projecting 12 years of drilling in the slide deck. This year, you're planning to drill about 11 wells. Is the inventory calculation straightforward? Would that figure also account for any delineation work you've completed?

The calculations are not simply a comparison of the current 2025 TIL count to a multiple of years. Instead, we are examining our three-year average for the number of wells we've drilled and using that as the primary reference. We're also translating this into monetary terms and maintaining the capital expenditure from the past three years as the benchmark. By reducing costs, we can drill more wells within a specific timeframe while sustaining production levels for the same capital outlay. Therefore, there are two complexities beyond what you mentioned. First, we are analyzing a three-year average. Second, we are considering the capital spending and adjusting for our future costs.

And our next question comes from Derrick Whitfield with Texas Capital.

With respect to the shareholder letter, Tom, I'd like to go a different direction with it and ask for your perspective on how your PVIs compare across the basins, while we all have inverse incremental assessments, our data quality and look-back assessments are less accurate than yours, particularly on a leading-edge basis.

Well, I think we've said publicly that in 2025, the highest PVIs in our portfolio coming from our Marcellus project, and we're very happy to say that. And I just want to kind of reinforce comment Blake made in one of the earlier questions. We have made that project. Our team in Pittsburgh has made that project so much better. We've lowered our costs dramatically. We've gone to longer and longer laterals. And in many cases, that's four-mile laterals that involve fewer pads, fewer intrusion into the community there. And we're seeing historically high well performance. So very pleased to say that the highest return in our portfolio this year is the Marcellus.

Great. And then maybe for my follow-up, I wanted to focus on gas marketing in the Permian. In light of all the recent pipeline announcements that have achieved FID and the flurry of power announcements we're seeing, how are you guys thinking about managing your Waha exposure? And could this amount of incremental egress lead to favorable in-basin exposure if oil prices remain depressed?

This is Michael. I'll take that question. We have struggled in the third quarter with low Waha gas prices. I think everyone sees that. And so the long-haul pipes are important to reduce the basis between Waha and NYMEX. And we're a part of all the conversations with the new pipes that are being announced. So we're looking at opportunities to put some of our gas that we can take in kind on those pipes and provide ourselves not only the flow assurance that we want, but also that increase in price at that NYMEX market.

Our next question comes from Phillip Jungwirth with BMO Capital Markets.

I wanted to come back to some of the major projects in Culberson this year, the Barba-Row Phase 1 and the Bowler Row, see if you had any updates or takeaways as far as cost efficiencies, early time productivity. I think Barba-Row is expecting second-half wells online. And I know it's early, but Bowler starting up in the fourth quarter.

Yes, Phillip, this is Blake. I'll take that. Everything is coming on as expected, performing well, contributing mightily to the oil beat we just announced for Q3. Those projects are ramping up throughout the year. And we continue to enjoy the wonderful cost efficiencies in Culberson County, all the things we've highlighted in many previous decks. It is still the crown jewel of capital efficiency. So performing very well.

Okay, great. I'm curious if you've looked at lightweight proppant and if it's something you would consider using in your Delaware development. I understand you won't be producing it in your own refineries but would be purchasing it more through third parties.

Yes. We have a trial ongoing, as a matter of fact, on new lightweight proppant. So we don't have any results to share today, but that's a technology that we're investigating, and we have a lot of hope to see improved productivity as other operators have discussed.

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

Yes. I just want to again thank everybody for joining us. We had a great quarter. We've got a bright future, and we really intend to demonstrate to the marketplace that the Coterra model is resilient through the commodity price swings, and we're going to continue to deliver excellence as I hope we're known for. So thank you all very much.

Thanks, Tom. And this concludes today's conference call. You may now disconnect. Have a great day, everyone.