Thank you for standing by. Welcome to the Range Resources Fourth Quarter 2025 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Laith Sando, SVP, Investor Relations at Range Resources. Please go ahead, sir. Thank you, operator. Good morning, everyone, and thank you for joining Range's Year End 2025 Earnings Call. With me on the call today are Dennis Degner, Chief Executive Officer, and Mark Scucchi, Chief Financial Officer. Hopefully, you've had a chance to review the press release and updated investor presentation that we've posted on our website. We may reference certain slides on the call this morning. You'll also find our 10-K on Range's website under the Investors tab, or you can access it using the SEC's EDGAR system. Please note, we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. We've also posted supplemental tables on our website that include realized pricing details by product, along with calculations of EBITDAX, cash margins, and other non-GAAP measures. With that, I'll turn the call over to Dennis. Thanks, Laith, and thanks to all of you for joining the call today. In the fourth quarter, Range continued its steady progress on key themes that we have discussed over the past year. We executed on our plans safely and efficiently, delivering consistent well results, free cash flow, returns to shareholders, and steady activity levels that support Range's multi-year development plans we've previously communicated. All-in capital came in at $183 million, while generating production of 2.3 Bcf equivalent per day for the quarter. For FY 2025, we invested $674 million in capital, placing us squarely within the previously improved guidance, while generating production for the year at approximately 2.24 Bcf equivalent per day. This production level was a result of strong well performance and continued optimization of gathering and compression infrastructure that was mentioned on our previous calls. Diving into the quarter, Range operated two horizontal rigs, drilling approximately 225,000 horizontal feet across 15 laterals, averaging 15,000 feet per well. For the year, the team drilled 69 laterals with an average horizontal length of 14,800 feet, with our total activity exceeding 1 million lateral feet drilled. Our large, contiguous acreage position affords us the ability to drill these type of long laterals, increasing efficiencies and allowing us to access more reserves from a single location, all while reducing our overall development footprint and consolidating infrastructure requirements. For completions, the team ended the fourth quarter, completing approximately 1,200 frac stages. Completion efficiencies for the fourth quarter approached 10 frac stages per day per crew, pushing our 2025 totals to nearly 3,800 total stages and setting a new yearly frac efficiency benchmark of 9.7 stages per day. While we are proud of these achievements, we are equally proud that the team accomplished this while delivering on one of our best safety performance levels for the company. During the quarter, our supply chain team also completed the annual RFP for services process. The result was pricing for 2026 drilling and completions, materials and services that are flat to slightly lower than 2025 levels. In addition, multiple long-term agreements are in place to provide service pricing stability throughout the year, including the continued use of a base electric hydraulic fracturing fleet, which began a new two year term agreement on January 1, 2026. Our RFP results, coupled with our operational efficiencies, should continue to provide a strong foundation for peer-leading well costs and capital efficiency while creating options for future growth. Shifting over to marketing. Consistent with themes we highlighted on the last call, U.S. energy exports continued to set new records in the fourth quarter of 2025. We are seeing this across both natural gas and NGLs as global demand for reliable, affordable supply continues to support growing exports from the U.S. for multiple products. For context, LNG exports averaged over 17 Bcf per day in the fourth quarter, which was up 10% from the previous quarter. Waterborne ethane exports were estimated at 622,000 barrels per day for the quarter, up over 40% year-over-year and 24% sequentially. Lastly, LPG exports were up modestly year-over-year and are expected to benefit significantly in 2026 from new U.S. export terminal capacity. We believe this will be helpful in improving propane storage levels over the course of 2026, particularly on a days of supply basis. In January, Winter Storm Fern proved to be a meaningful demonstration of the energy security provided by America's position as the world's leading energy exporter, as demand for natural gas to feed power plants and heat homes increased rapidly for several days in late January, approximately 5 Bcf per day of LNG feed gas was redirected to serve the needs of U.S. citizens. When temperatures warmed closer to normal levels, LNG feed gas exports ramped back up to pre-storm levels just as quickly. This weather also provided for strong bid week pricing for the month of February, which settled at over $7 per MMBtu. The gas marketing and operational teams did a superb job coordinating a production and sales plan, locking in strong free cash flow by selling nearly all of Range's natural gas during bid week. At the same time, the liquids marketing team picked up additional revenue by optimizing ethane extraction and selling more BTUs locally as natural gas. During the quarter, Range also executed a long-term sales agreement that will link gas from our planned processing expansion to a new power plant in the Midwest. The plan is expected to start up in late 2027, with the transaction set at an attractive premium relative to a Midwest index. We continue to support the development of a number of prospective projects in the power generation and data center space. While many of those projects are concentrated in our backyard, we are also seeing interest in other regions where we have transportation capacity, as evidenced by the deal just mentioned. We believe there will be several near and medium-term opportunities for Appalachian Energy to meet the growing demand for energy in North America and around the world. We look forward to reporting on more Range-specific opportunities as they progress. Turning to our go-forward plans. Range's strategic multi-year operational plan has built up more than 500,000 lateral feet of growth-focused inventory to support future development. This is approximately 100,000 more lateral feet in inventory than previously discussed as a result of the continued strong drilling performance mentioned earlier. This additional duct inventory provides Range added flexibility to align our future reinvestment plans with market fundamentals. Simplistically, we can reduce our previously communicated 2027 capital and still produce 2.6 Bcfe per day next year. We could maintain a similar operational cadence with $650 million to $700 million in capital for 2027 and set up continued growth into 2028. We are in great position to see how demand shapes up over the next 24 months and respond accordingly. Looking more closely at 2026, we expect to continue an operationally efficient program that utilizes a single full-time super spec drilling rig, paired with a second rig utilized throughout the second half of the year. On the completion side, we anticipate running a single full-time electric frac crew, while picking up a spot crew for the second and third quarter to harvest some of our DUC inventory. This drives an all-in capital budget of $650 million to $700 million, which consists of the following: approximately $500 million of maintenance D&C capital, an incremental $120 million to $140 million of D&C growth capital that is primarily allocated to a second completions crew, $15 million to $35 million in land for targeted acreage. This acreage capital is less than prior years, as we have held more acreage with production, allowing maintenance land spend to decrease. Also included in the acreage budget is capital that supports increased lateral lengths, which can offset some or all of the lateral footage being turned to sales during the year. Lastly, we also plan to invest $15 million to $25 million for software and production facility upgrades to further reduce emissions. By year-end, we will have completed the pneumatic retrofit project that was started in 2024. This total capital investment plan of $650 million to $700 million is consistent with prior discussions and will result in production of 2.35 to 2.4 Bcfe per day, while carrying significant momentum into 2027. Looking at the year ahead, the shape of our production profile is expected to look similar to prior years, as we project first quarter production to be down versus Q4 of last year. As we commission sizable gathering and processing expansions at mid-year, you will see production step up meaningfully in the second half of 2026 and continue into 2027. We are excited about how the company is positioned today, with financial and operational flexibility that allows us to efficiently align production growth with sales to known-in markets, while generating free cash flow and returning capital to shareholders. We believe our robust inventory and relatively low capital intensity provides Range a differentiated foundation for generating through-cycle returns for our investors. I'll now turn it over to Mark to discuss the financials. Thanks, Dennis. 2025 again demonstrated the strength of Range's business. Throughout commodity cycles, we intend to generate free cash flow, prudently invest in the business, and return capital to shareholders. Range accomplished just that, generating cash flow from operations before working capital of $1.3 billion and over $650 million in free cash flow while priming the business for future growth, enabling an operational and reinvestment strategy that maximizes our competitive advantages to enable value capture from increasing long-term demand across the U.S. and internationally. Consistent with prior years, Range's free cash flow was enhanced in 2025 by realizing a price greater than NYMEX Henry Hub. NYMEX natural gas prices averaged $3.43 for the year, while Range achieved an average hedged realized price of $3.60 per unit of production. A $0.17 premium created by commodity mix, hedging strategy, and our advantaged portfolio of transportation and sales contracts that provide access to geographically diversified sales points, linking Range to customers in key U.S. and global markets, delivering roughly 90% of revenue from outside Appalachia. Alongside higher realized prices year-over-year, Range expanded its margins, growing per unit of production cash margin by roughly 20% to $1.64 per MCFE, or approximately 3x our maintenance, drilling, and completion capital per MCFE. Premium pricing, strong operational execution, and competitive full-cycle costs generated enhanced free cash flow and enabled growing shareholder returns. Range paid $86 million in dividends, invested $231 million in share repurchases, and reduced net debt by $186 million while investing in operations that support our growth plans through 2027. Over the last several years, Range has reduced debt by a total of roughly $3 billion. With a strong balance sheet, we have increasing flexibility to make opportunistic investments. As of year-end, Range has purchased over 33 million shares since the program's initiation in 2019, investing $744 million during that time frame. To position the share repurchase program for the future, our board has increased the currently available capacity to $1.5 billion. In addition, the fixed per share dividend is something that we expect over time to grow slowly and reliably. We expect to increase the quarterly dividend by a penny per share, or 11%, at the next announcement. We critically evaluate investment opportunities and shareholder returns with an unwavering focus on sustaining and further enhancing Range's core objective: durable and growing per share free cash flow. To achieve that objective, we seek to enhance our low full-cycle cost structure, low reinvestment rate, and durable margins. Like Dennis mentioned, Range could hold 2.6 Bcfe per day of production with less than $600 million of annual drilling and completion capital, or less than $0.60 per MCFE. Here's a key message we repeat today: We can thoughtfully grow Range's business in conjunction with increasing market demand, allowing us to grow the value of the business and deliver additional returns to shareholders. This is a consistent long-term strategy underpinned by quality, long-duration assets, and a strong balance sheet. As the U.S. and global natural gas markets continue to integrate with commissioning of LNG facilities, while domestic demand grows substantially, primarily from the need for additional gas-fired electric generation, we believe Range's long life inventory creates enormous option value by serving an integral role as a long-term energy supplier. Our durable free cash flow, evidenced through cycles, positions Range to consistently deliver value to its shareholders. Dennis, back to you. Thanks, Mark. Range's results continue to reflect a consistent theme: strong operational performance against our stated multiyear plan, consistent free cash flow generation, and prudent allocation of that cash flow, balancing returns of capital, balance sheet strength, and the optimal development of our world-class asset base. As we sit here today, our multiyear plan, communicated just one year ago, is on track in generating the results you've come to expect from Range. Years of disciplined planning have placed us in the strongest position in our company history, having de-risked a high-quality inventory measured in decades and translated that into a business capable of generating significant free cash flow through cycles. We have more opportunity in front of us more than ever. With that, let's open the line for questions. Thank you, Mr. Degner. The question-and-answer session will now begin. If you would like to ask a question, please indicate by pressing the star key, then one. If you are on a speakerphone, please pick up your handset before asking your question. If you would like to withdraw your question, you may do so by pressing star one one again. The first question is from Scott Hanold of RBC Capital Markets. Your line is open. Yeah, thanks. Good morning. Could you give a little more color on the cadence of production you're expecting in 2026? I know you said there's a step up in the, you know, kind of the mid part of the year, but give us some context on the size of the step up. What's needed to get there in terms of infrastructure adds? Just more broadly, on your typical cadence, you know, would you guys ever, you know, look to, you know, effectively, you know, drive higher production in sort of the first quarter versus, say, the midyear, given that, you know, you do see much more premium pricing, especially in Appalachia during the winter? Yeah. Good morning, Scott. Thanks for joining our call this morning. As we start to think about 2026 and the production cadence, I know you heard us touch on this during the prepared remarks, but really, the character will look in the first half of the year, pretty similar to what you've seen from us over the prior several years, where you see a ramp at the end of the year with turning lines that get executed and wells completed and turned to sales, let's just say, during the mid part of that prior year. That carries momentum into improving commodity prices, which you're pointing to, and in the winter months. That's what you'll kind of see from us for through this cycle as well. On a relative basis, Q4 was roughly 2.3. You'd expect Q1 to look roughly like 2.2 Bcf equivalent per day. With some of the fluctuation also being driven by ethane extraction fluctuations, where we had a real opportunity to take some ethane, reject it into the gas stream, take advantage of some pricing opportunities during the last few months, and then turn that back into ethane extraction when you see prices then fluctuate back the other way. All in all, about 2.2 Bcf in the first quarter. Between now and the first half of the year, when we see the next wave of infrastructure get commissioned, you would expect to see us be kind of between that Q4 level and Q1 as we continue to utilize existing infrastructure at a high level of utilization. At the midyear point, we've got some processing that comes online, that's around $300 million a day of capacity, of processing capacity that will go into service. Then on the back end of the year, that's where you'll see the ramp really take shape. That carries momentum at the back end of 2026 into improving commodity prices for the winter of 2026-2027, and then through 2027 as well. So what should the end of the year look like? Our forecast internally has us at a year-end type production level of 2.5 Bcfequivalent per day, so, plus or minus, around that level. Significant ramp at the end of the year on the back of turning lines in the middle of the year, second frac crew for Q2 and Q3, and then kind of carrying that momentum into 2027. It should be an exciting year for us as we think about our production profile and activity. I appreciate that. That's helpful. As my follow-up question, you know, obviously, you all signed that, or a power contract for the Midwest, and you talked about, you know, potentially some other, you know, things out there that you'll continue to evaluate. Can you give us a little bit of color on what kind of premium you were able to capture there? Like, what is the benchmark we should be thinking about and how much of an uplift? You know, do you see a lot more of these opportunities, you know, like this? You know, what do you kind of see that, you know, maybe through the next year or two? As you can imagine, we're pretty excited about the announcement. We've been really talking about this for the better part of a year now around these kind of opportunities in the background. Lots of discussions being had between, it's just Range, between Range and end users that are needing assurity of supply for a multi-decade investment decision for infrastructure. We think in some ways this is the first of many opportunities you could see Range participate in. As you've heard us talk about, given our really depth of inventory and the quality of it, and the diverse transportation portfolio that we have, that allows us to not only consider building or supplying for energy demand in the basin, but also kind of in the region. We think there's a lot of reasons for us to be excited about, as you can probably tell from my voice this morning. What's out there that's in addition to this? I mean, I think, you know, the deal that we signed, though, it's difficult for us to share the confidential terms of that arrangement today, just given some asks we have from the counterparties associated with it, this is also something that's scalable. We see there's additional conversations around how we can participate in the scalability of not only this particular infrastructure, but also what builds out in the region. Of course, you've got, closer to home, the Fort Cherry project, which we're continuing to see what I would say, you know, reasonable progress to narrow down to an end user that could utilize gas that's right out of our producing assets, that the facility would be built right on top of us. I think there's a lot of ways for us to win, is what I would point to, whether it's utilizing our transport or seeing someone build directly behind the meter, right in the heart of the field where we produce our NGLs and our natural gas. I think it was encouraging last night during the State of the Union to also see some commentary around the willingness to encourage end users to, I'll just say, bring their own power. We think that aligns really well with companies like Range, which again, are going to have multi-decades of Marcellus high quality inventory that can provide a significant backstop to those future needs. Appreciate all the color. Thanks again. Thank you, Scott. Thank you. The next question is from John Annis of Texas Capital. Your line is now open. Good morning. Thanks for taking my questions. For my first one, you laid out optionality beyond 2027, where you can either continue growing production or hold at that 2.6 Bcf a day level. Can you walk us through what signposts or criteria will ultimately drive that decision? I know there's a lot of time between now and then. I was just curious whether this decision would be driven by a view on the commodity or more demand led, like tying growth volumes to additional gas supply agreements. Yeah, good morning. Thanks for joining us. When I think about the next couple of years, really the production profile that we've laid out really starts with a couple of things, and primarily, it's generating free cash flow. When you think about how lean the operation is, with 1.5 drilling rigs and 1.5 frac crews, you're really talking about a low capital intensive business for us that allows us, due to the inventory and productive capacity that we've built over the last couple of years, it allows us to really generate that thoughtful wage of growth through the next couple of years, and doing so in a capital efficient manner, that would be difficult, we believe, to replicate by others in the sector. I think when you think about the other drivers, you know, clearly, you know, we feel like commodity pricing, back to the cash flow statement, is in place both on the nat gas side and on the NGLs that would support this production profile. We also have transport that goes along with it to feed future growing demand. We were able to pick up some capacity on Energy Transfer's Rover system a year ago. That capacity is not an expansion, but is actually taking on market share out of the basin. Think about it as being growth for Range, but not necessarily growth for Appalachia. Again, we think that was part and parcel because of our ability to have a longer term view for demand and also our inventory, and getting our inventory and production to that in demand use. As I think about the next 24 months, if I kind of take a step back, we've got the infrastructure in place, we've got the inventory and very capital efficient program to help deliver that into that expansion of infrastructure and growing demand over the next 24 months. The exciting thing is we really have the ability when you start to think about beyond 2027, we've got really a theme that you've heard us say over the past few earning calls. We've got a lot of flexibility built into the program where we can pull down capital and maintain a production profile that's in excess of 2.6 Bcf equivalent per day in 2028 and beyond, with something that's in the neighborhood of, you know, sub $600 million in CapEx. Think about it differently, less than $0.60 per Mcfe. We could continue to have a thoughtful wage of growth depending upon future demand and deals that are worked on our end. You know, as evidenced by our announcement today on the marketing side, we would have the ability just to continue this momentum with a capital profile that looks very similar to what you've heard us communicate for 2026. We really think we've set the business up for the right kind of optionality as demand continues to materialize, and we would be able to deliver into that space in a very capital efficient manner that you'd come to expect from us. I appreciate all that color. For my follow-up, your 2026 gas differentials are roughly in line with where you've been running. I wanted to get your views on at what point would you expect structural in basin demand growth to begin compressing Appalachian basis differentials? Does the current guidance already embed any early benefit from the mid-2026 takeaway additions, or is that a 2027 and beyond story? Yeah, this is Mark. I'll kick that one off. As we begin the year with guidance, really it's driven by the significant portfolio of transportation options that we have, where we're delivering gas outside the basin. It's what the market indicated levels are at the myriad of sales points we have across the U.S. That also bakes into account the seasonality that is a natural part of the business and a natural part of prices across the U.S. for those differentials. Now, as we set that guide, based on market levels at the beginning of the year, also keep in mind, over the course of the year, that Range's marketing team has been at this for a long time, optimizing that sales portfolio, optimizing around opportunities that present themselves based on weather or other needs or interruptions in service by some parties, and our extremely high levels of uptime and being able to capture market runs, be it weather generated opportunities or otherwise. Those numbers do get refined over the course of the year, but it does all come back to the portfolio of transportation options we have. One other piece I would say is the team's ability to provide some stability and predictability in pricing that's realized. It's been Range's practice for a long time to take pricing at first of month for about 90% of our production volumes. That has proven to be a very successful way of capturing strong prices when they're when they present themselves, providing stability and predictability in your realizations. The other piece of it is based on the fundamental research we do internally, of course, supplemented with outside research, we can shape that a bit. Sometimes it's more than 90%, perhaps it's sometimes a little bit less. I would also layer into that, something Dennis mentioned a moment ago, that we can alter ethane extraction levels and increase natural gas sales or ratchet up the extraction levels of ethane. Prices and net margins are better. There's a whole host of factors that play in there to that, basis differential. Again, what it all comes back to is the business that has been built on top of Range's asset, and that footprint that allows us to access a host of markets across the U.S. and maximize the value of each molecule we produce. It's about growth and cash flow. It's about growth and cash flow per share, not just about growth or production or scale for scale's sake. Makes sense. I appreciate the time. Thank you. Thank you. The next question is from Douglas Leggate of Wolfe Research, your line is now open. Thank you. Good morning, everyone. Dennis, I wonder if I could ask you about the cadence of the DUC capacity. I mean, you've given a little bit of color here, but you obviously have a lot of options here. Gas prices have weakened again. What would cause you not to bring on that production if gas prices did indeed prove to be softer for the balance of the year? Yeah, good morning, Doug. I think when you look at the balance of the year and the timing at which the infrastructure, you know, let's just say, basically starts to come into service, which would really be end of Q2, type timeframe, we kind of feel like the timing really works well when you start to think about the wells that'll get turned in line or a portion of that DUC capacity that starts getting completed in the second quarter, and then our ability to basically then start to see that production turn into, spinning the sales meter through the back half of 2026. We feel like the timing is set up complementary to improving pricing as you start to get into the end of injection season, which, you know, internally, you know, our view is, depending upon just a normal weather outlook for the summer, we would anticipate to really see a number of around 3.6-3.7 TCF, so in the ground. With that in mind, and the infrastructure, the timing, we feel like it really is kind of coming together as expected. We'll have around 900,000 lateral feet that gets turned to sales in the balance of 2026. Just like you've seen in the past few years, there's always some flexibility that we leave in the program to, we'll just say, take advantage of different commodity price signals. As an example, some of our dry gas is right now planned to turn in line toward the end of the year, as you would expect, to take advantage of improving fundamentals as we start to go into the winter, out of our Northeast PA asset. We think we've got the right playbook in place for now, but we always leave some flexibility that we could also take some of those tails, push them deeper into the year if the signals warrant. When you look at where we are from a commodity price standpoint and how we've risked the program, we feel like the cash flow we've communicated that would be delivered from the business is intact. We also feel like the reinvestment rate will remain really low going forward. We feel like the fundamentals are all really there for us today. I appreciate that. I guess it's kind of a curtailment strategy, but not quite, if you know what I mean. It's in terms of, you know, you selling into the strength of the market. We're just trying to understand the physics of it, so thank you for that. My follow-up is, if I could kind of play it to you like this, your balance sheet is in terrific shape. You don't really need to hedge because your breakeven is as low as it is. I guess my question is, we're all used to the entire industry for the last however many years we've been doing this, 20, 30 years, selling into bid week just because that's the way the industry works. It seems that you leave an awful lot of spikes on cash market pricing. Now, I might be oversimplifying it, but I guess my question is, why bid week sets the pace, given how good, you know, a position, your capital structure and so on is in at this point? Why not let more float on the cash market? I'll leave it there. Thanks. Yeah, really good question. I think what I would do is take a step back and really just spend a couple of seconds here talking about how we view bid week. I think if you were to ask the question, or look back at when we talked about bid week and our participation, I think roughly what you've seen us commit to is roughly plus or minus 90% to be committed in the bid week process. What goes into that is really a, I'll just say, utilizing internal resources, a multidisciplinary team that's very talented, that involves some of the same expertise that is a part of our hedging committee to also our operations team. How are we viewing, let's just say, what lies ahead from weather, from a macro perspective, also to any operational maintenance that we would expect and new well turn-in lines. What that does mean is that we do toggle as we walk into the bid week based upon what pricing we see at that time versus what we believe to be most reflective of what the next 30 days reflects. You do see us toggle that percentage contribution into the bid week that's committed. As you think about February, as an example, we kind of walked into that timeframe with a much stronger view on the pricing on the front side. We put 97% of our gas into the bid week process to try and capture what we believed was strong pricing and turned out to be excellent pricing. There are other times when we've backed off of that to also have more exposure into what we believe is fluctuations in commodity price. Of course, lastly, some of our new production may not always go into, meaning new well turn-in lines, may not always be accounted for in that bid week process. Again, we could capture pricing through the balance of that 30-day cycle. Shortly, or just put simply, I think we try and balance both, but it really is a complicated process that we try and walk through to make sure that we're delivering the best, you know, best returns. Appreciate it, guys. Thanks so much, Dennis. Thanks, bud. Thank you. The next question is from Jacob Roberts of TPH & Company. Your line is now open. Good morning. Morning, Jake. Dennis, I appreciate the color on kind of the 2027 plus timeframe. I was wondering if you could opine on where you view service costs over that same time period. Really what I'm getting at, is there a willingness to convert some of that DUC backlog into more of a deferred till approach, you know, if you do expect service costs to rise over the coming years, and also potentially to be a little bit quicker to the market with volumes potentially in a better pricing scenario? Yeah. Good morning, Jake. I think when I start to think about the upcoming, you know, couple of years, I think the reality is we have baked in a lot of flexibility and options for us to think about timing of turn-in-lines, well mix, how we would think about, you know, our liquids contribution, at what time of year, of course. I think the short answer is yes, we would absolutely want to factor in what's the best and most optimum way to basically think about our turn-in-line cadence as we kind of move forward. From a service cost perspective and the role that that would play, I know we touched on it in the prepared remarks, but we've kind of seen what I would call is, you know, low to mid single-digit kind of relief in service costs. As we're kind of planning for 2026, some of the costs are going to be fairly secured with multiyear agreements. As you can imagine, that's been a part of our program on an annual basis. Then some are gonna be more on a 12-month type structure, where you're gonna see more float in what's taking place year-over-year. It does feel like, just given the efficiencies that we've all seen, and especially Range, with some of the numbers we've talked about on the Drilling and Completion side, it's lended itself to really maximum utilization of one to two type frac crews or drilling rigs to still see the kind of growth that we're talking about, where you can generate 20% over a multi-year program, which is kind of exciting. I say all that to say, I don't know that I expect service costs to really go down a whole lot more. It feels like we're reaching a bit of an asymptotic trend on the bottom end here, where, you know, we're just kind of reaching a close bottom, if you will, and we're wringing out those additional dollars through other operational efficiencies, water recycling, multiple stages a day, improvements in surface equipment design. Long-winded answer to say, we would fully expect those savings to be an opportunity to think about either not spending all of our capital in a given year, thus the $50 million capital range, or again, as we think about 2027 and beyond, does that get invested into another thoughtful wedge of growth, depending upon demand that continues to emerge and materialize? Thank you. That's, that's super helpful. I did want to circle back to the supply agreement, you guys signed, which, you know, I agree, is very positive to see. I'm curious, if the $75 million to this specific facility is a starting point for this facility? Is there the potential to grow those volumes? Maybe if not, is this specific counterparty someone you could view as, someone you'd pursue additional projects with over the coming years? Yeah, Jake, I think the short answer is yes. This is a facility that will require more than $75 million a day in gas feedstock to generate power. This was a, quote, "A good starting point." There is scalability to the infrastructure, both at this site and in the region, that we could help meet going forward through the same transport that we have. This is all in line with some of the transport that we've picked up that will start in service in 2027 as a part of our multiyear plan, but also could be served through other transport that we actually have or other capacity we have on that same piece of transport. Yes, it's a great counterparty. It's, it's a really high quality counterparty on top of it. We really think it sets up a strong foundation for how deals could get structured that allow growth, that's also margin enhancing going forward. Thanks. I appreciate the time. Thanks, Jake. Thank you. The next question is from Phillip Jungwirth of BMO Capital Markets. Your line is now open. Thanks. Good morning. Morning. Coming back to the question around growth beyond 2027, wondering how you would consider allocating capital across liquids versus dry gas acreage? When would you need to commit to additional processing capacity or other infrastructure if you decide to grow, or is there any willingness to focus more on the dry gas side and take in basin pricing? Yeah. Good morning, Phil. When we start to look at the inventory, we do have dry gas inventory that will continue to play a role in our program on a go-forward basis. I know looking at this year and prior years, it's tended to fluctuate somewhere between probably 20-30, 35% of the program on an annual basis. There is the ability for us to flex that higher if warranted. I think a good example is just seeing some of our activity in Northeast PA, where we've had some high quality, Lower Marcellus wells that we've been able to drill on an annual basis, where we've taken a rig, drilled 1 to 2 pad sites, and incrementally utilized existing infrastructure and incrementally added some nice production to the profile. We do have, I'll just say, quote, "More of that we can do," if we wanted to flex into a direction of being drier. As far as an infrastructure commitment standpoint, you know, the Harmon Creek 3 processing expansion that goes into service this year really carries a significant amount of momentum through 2027 and to the back as we start to think about getting into 2028. There is some debottlenecking that is underway with one of our midstream partners, MPLX, at the Majorsville facility. Quote, "We're wringing out more with the same infrastructure to look for incremental capacities there," and gives us the option of growing production in the future without having to consider a new processing plant construction alone, which we think that's where we're at from a maturity of the business standpoint. I know you've heard us, Phil, talk about it in the past, where we think, given our depth of inventory that we have, it's going to afford us the ability to step into capacities that others could let go underutilized in the future. In the near term, maybe it's more also debottlenecking and wringing out some capacity that can be more efficiently utilized in existing processing plants and gathering. That's how we're thinking about future growth, and we think the near term, or the timeframe it would take to actually see those molecules go into service is if that timeframe gets truncated, which again, gives us more flexibility. Okay, that's helpful. Then you also had a new macro slide on global naphtha cracking rationalization. I was just hoping you could touch on this. Is it incremental to what you're also showing as call on U.S. supply for NGLs? Then just given the petchem margins are at historical lows, how would you think about operating rate assumptions, or is what you're showing here a little bit more reflective of something closer to mid-cycle margins? The NGL macro has been, you know, clearly a hot topic as we think about the back half of 2025. I'm gonna attack this from a couple of different angles, but, you know, clearly, stock levels have been elevated through 2025, both on the propane and also on the ethane side. You know, I think each has a different story to tell, but in some ways, they've got a similar story. The different part of the story is, you know, for propane, you had weak demand last year, and of course, there was a increased level of production that was a little stickier, I think, through associated gas contribution than, you know, maybe was somewhat anticipated. On top of it, you did have, on top of the demand being down a little bit and supply being pretty resilient last year, you also were a little bit lagged in seeing run rates improve on some of the infrastructure that was commissioned in 2025. Export capacity, maybe the common ground is the export capacity expansions out of the Gulf have been really helpful to see the ability to move another 200,000 to 300,000 barrels a day. You're seeing that materialize now in the numbers as we've started to get out of fog in the ship channel and other operational hiccups that have transpired, and you're really seeing strong numbers now in the two million barrels per day type level on the propane side, as an example. As we think about rolling the tape forward for 2026, you really start looking at more utilization of the current dock expansions. You've got additional dock capacity that will get also commissioned through the balance of the end of the year with some of the same midstream providers that commissioned infrastructure last year. On top of it, you've got, I'll just use Ineos and Sinopec as an example. You've got close to 200,000 barrels of incremental demand that goes into service here over the balance of the next 12 to 18 months. We're still optimistic, and really, as we're thinking about stock levels getting pulled down, renormalized through the balance of 2026, and then run rates continuing to improve on infrastructure that was commissioned in 2025 and through the balance of the back end of 2024. I'd say this: we would also expect to see a lower growth rate with some of the NGL contribution out of the Permian and associated gas, just given some of the downward pressure to their growth associated with oil price today that we see. Hopefully this gives you the color you're looking for, but it's definitely a complicated math problem, but we see at the end of the year that the stock levels get renormalized and pricing return to a healthier place. Yeah, that's a great overview. Appreciate it. Thanks, Phil. Thank you. The next question is from Kevin MacCurdy of Pickering Energy Partners. Your line is now open. Hey, good morning. Dennis, at the end of your prepared remarks, you mentioned that Range had initiated this growth plan a year ago. I wonder if you could take a step back and compare the in-basin demand and supply outlook today, compared to when you initiated this growth plan and maybe your confidence on that outlook? I guess the context of this question is that, although we've had a lot of price volatility over the past few months, as it sits today, the curve is, you know, pretty materially lower than it was a year ago. Thanks. You bet. Thanks for joining us this morning, Kevin. I think when we start to think about what's different between a year ago versus today, in some regards, the way we I think I may have touched on this a little bit already, but I'll try and not be too repetitive, but we did try and risk the program as we were thinking forward around what pricing could look like. Yes, it is down a little bit today, but I would say by and large, it's really kind of intact to what how we had risked the program and the cash flow that we felt like that the business would throw off. The way we also structured the program was around using existing capacity, though. We didn't really build it around the premise of new demand that might come. Instead, it was taking on the Energy Transfer's Rover Pipeline incremental capacity of around 250 million a day. It would get us to both the Midwest and also the Gulf markets, which we're marketing at on a regular basis through existing capacity as we speak. We felt like it allowed us to take on market share instead of thinking about growing for growth's sake. That's not a part of the equation for us as we go forward. We have to have a home for those molecules. We felt like taking on that market share was... ... indicative of our ability to have a depth of inventory that would be the backstop for a commitment to this pipe. We also felt like that pipe capacity got us to end markets that would see growing demand in the future. Good optionality and flexibility as we move forward, and we were able to step into that capacity at a great time in our program. When we think about 2028 and beyond, I think that's where the growing demand piece really starts to become a bigger topic for us. I think that's evidenced by the marketing deal that you're hearing us talking about. We think it's the first of many options that we could consider more in basin or regional, that allows us to think about that next wedge of growth, but it also has to materialize. More market share as a part of our plan now, we feel like pricing is still intact. That allows us to continue to execute the current plan that we have for the multiple years. 2028 beyond, it will be based upon a home for that production and the in-basin and region demand that materializes. That's a really good answer. Maybe as a follow-up, I wanted to dig into your differential guidance a little more. Your fourth quarter realizations were strong, but your guidance for differentials are pretty similar year-over-year. We saw first quarter gas prices, you know, strong in the Northeast relative to Henry Hub. Can you kind of square, you know, why the guidance is the same year-over-year, and give us any comments on how realizations will look throughout the year? I think as I started one minute ago, we start with just the market indications. Information content and forward curves is what it is. It's not perfect, but it's the starting point, the best predictor we have. Our guide is about $0.05 better year-over-year versus the starting points. As we think about how 2026 has begun, we're off to a great start. I think it's important to note that 90%+ we take into first of month, capturing extremely high value. Variation quarter-over-quarter, and the seasonality that drives that variation year-over-year, again, is somewhat weather dependent. But ultimately, the consistency of our tight differential and our premium to Henry Hub realized price per Mcfe, is a function of the transportation portfolio. You know, I'll just leave it at that. The guide is market indicated, and we'll continue to improve that through the experience of our marketing team, as we do every year over the course of the year. Appreciate that. Thanks. Sure. Thank you. Thank you. The next question is from Michael Scialla with Stephens. Your line is now open. Good morning, everybody. Just wanted to ask on your return of capital, it's been heavily weighted to buybacks. You are increasing the dividend this year. Do you expect any inflection going forward, or how are you thinking about allocation between the balance sheet and dividends and buybacks going forward? Sure. Good morning, Mike. I think, as we evaluate what the current trading levels of stock price versus an NAV, what the fundamental value is of an inventory measured in decades versus a stock that trades close to just your approved reserves, which is, you know, less than a five year development plan, we see tremendous value in buying back those shares. I would expect us, for the foreseeable future, to continue favoring buybacks. As you look at the trend, I would also expect us to slowly, steadily grow the cash dividend. I think there's a discipline and a real tangible total shareholder return element there. It's a commitment to return capital. It's a commitment to maintain a balance sheet that can do that through a cycle and to steadily, slowly grow that persistently. As you think about the share repurchases, the scale, scope, timing, again, we have not given a formula quite intentionally. We think if you're formulaic and programmatic, you can end up with just a procyclical and buy high type program. We think the flexibility of being opportunistic generates a much better return in buying when you see pullbacks and at, you know, just lower points, lower entry points in the stock price. That is to say, we still see tremendous value in where the stock is trading today, and I think you can look at our track record of the last number of years, and the percentage of cash flow that we have deployed in returns of capital as compelling. We're not going to provide a framework, but for perspective, you know, we've been in the 20%-30% range the last couple of years. This year approached 50% of free cash flow in returns. As the balance sheet, as you stated, is in a great place, we have a lot of flexibility in how best to reinvest in Range's business and continue improving it. Yep, makes a lot of sense, Mark. I wanted to ask on slide 7, your free cash flow forecast for the next couple of years. You've given the assumptions there for production growth, prices and CapEx. Wanted to see what you're assuming for op costs. Do those stay flat or are there any efficiencies built in there going forward? They're flat. We've tried to shoot this straight, be pretty conservative. As Dennis said, we are approaching the lower limits in many situations on how far you can push costs down. Our focus, of course, is on wringing every penny out of the cost structure that we can, contractually and strategically. For purposes of modeling here, it's essentially flat. Is there any efficiency upside, that could benefit? I know you talked about, water infrastructure and some other places where you could save on op costs going forward. You know, the team always finds ways to get a few more stages a day done on average, more lateral footage per day, each rig that's in operations. We certainly shoot for and plan for a certain amount of that. Every year, we are fortunate with the strong and safe execution by the team and continuously surprised by what the Range team can do. I would certainly think that there's a little bit more there the team can wring out. Appreciate it. Thank you. Thank you. Thank you. We are nearing the end of today's conference. We will go to the line of Neil Mehta of Goldman Sachs for our final question. Yeah, thanks, team. I just wanted to circle back, Dennis, on Fern. It looks like you guys were able to run well through that period of time and sell into bid week. I don't know if there's any quantification you could provide around the cash flow uplift around the storm. Any lessons learned around it? I'm sure volatility is here to stay in the gas markets, and just any perspectives on how your marketing team performed during that period of time. Yeah, I think First of all, thanks for joining us, Neil. When I think about that, we Sorry, bid week and also the operating plan, you know, we were able to really lean into the pricing of that, you know, $7 type level, which was really significant when you think about the cash flow that gets thrown off during that kind of cycle. As you point out, this is something that we've talked about now for a few years. We expect to see more volatility going forward, whether that's weather related or, you know, driven by other factors. The team really did a great job, and I kind of have to congratulate the operating team because they were in some pretty rough conditions with subzero temperatures, and at any one point in time, we didn't have more than a pad site or two that was really down, that then didn't get restored in pretty short order. Team really did a phenomenal job, and I think this is years of planning and teamwork between our team in the field and also our midstream providers. Just from a standpoint, we continue to do winter operations, look backs and improving our production facility designs, rooting out downtime and sources of that downtime, so that we can preserve that flow from the wellhead all the way through the processing plant and get downstream to those critical end users, which, as we saw from Winter Storm Fern, that was really important. Even in this last week, for some in the Northeast, I'm sure they're feeling the effects and comfort of having natural gas flow into generating power for their homes these days. Our team did a really great job, and as you heard me touch on earlier, it's a multidisciplinary plan on how we think about capturing the value uplift during bid week or leaving more in the, in the daily to try and capture what we think is more of upside opportunity through the balance of that upcoming month. Yeah, we'd expect more volatility going forward in that multidisciplinary team will get leaned on a monthly basis. I think, Neil, we're not going to give any forward guidance on it specifically, but just conceptually, I'll say this, that February looks to be one, if not perhaps the best free cash flow and realizations month in perhaps company history. That's a great color. Well, that's a good note to end on, so I'll leave it there, because I know we're at the time. Thank you. Thanks, Neil. Thank you. This concludes today's question and answer session. I'd like to turn the call back over to Mr. Degner for his concluding remarks. You bet. I'd just like to thank everybody again for joining us on the call this morning. Really appreciate your support. If you have any questions, as always, please follow up with our investor relations team. We look forward to catching up with you on the road in a one-on-one or at our next call. Thanks, everyone. Ladies and gentlemen, thank you for your participation in today's conference call. You may now disconnect.