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Thank you for standing by. Welcome to the Range Resources Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions] 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 multiyear development plans we previously communicated. All-in capital came in at $183 million, while generating production of 2.3 Bcf equivalent per day for the quarter. For full year 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 2 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 leak 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 2-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-on-year and 24% sequentially. And 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. Then when temperatures warmed closer to normal levels, LNG feed gas exports ramp back up to pre-storm levels just as quickly. This weather also provided for strong bid weak 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 midweek. 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 lead gas from our planned processing expansion to a new power plant in the Midwest. The plant is expected to start up in late 2027 with the transaction set at an attractive premium relative to a Midwest Index. In addition, 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. Now turning to our go-forward plans. Range's strategic multiyear 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 DUC inventory provides Range added flexibility to align our future reinvestment plans with market fundamentals. Simplistically, we can reduce our previously communicated 2027 capital. It still produced 2.6 Bcfe per day next year. Or we could maintain a similar operational cadence with $650 million to $700 million in capital for 2027 and set up continued growth into 2028. So we are in a 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 completion 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. And lastly, we also plan to invest $15 million to $25 million for software and production facility upgrades to further reduce emissions. And 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 midyear, 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 the end 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 enable 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 $0.01 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 grew 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 1 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 derisked the high-quality inventory measured in decades and translated that into a business capable of generating significant free cash flow through cycles, and we have more opportunity in front of us more than ever. With that, let's open the line for questions.

[Operator Instructions] The first question is from Scott Hanold of RBC Capital Markets.

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 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. And just more broadly on your typical cadence. Would you guys ever look to effectively drive higher production in sort of the first quarter versus, say, the midyear, given that you do see much more premium pricing, especially in Appalachia during the winter?

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 in term of sales, let's just say, during the mid part of that prior year. And then that carries momentum into improving commodity prices, which you're pointing to and in the winter months. And so that's what you'll kind of see from us through this cycle as well. So 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 rejected 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 that fluctuate back the other way. So 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 -- I'll just say 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 -- 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 '26 into improving commodity prices for the winter of '26-'27, and then through '27 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 Bcf equivalent per day. So plus or minus around that level. So significant ramp at the end of the year on the back of turn in lines in the middle of the year, second frac crew for Q2 and Q3 and kind of carrying that momentum in 2027. So it should be an exciting year for us as we think about our production profile and activity.

I appreciate that. That's helpful. And then as my follow-up question. Obviously, all signed that -- a power contract for the Midwest. And you talked about potentially some other 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? And do you see a lot more of these opportunities like this? And what do you kind of see that maybe through the next year or 2?

Yes. As you can imagine, we're pretty excited about the announcement, and 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 held between -- just Range -- between Range and end users that are needing a surety of supply for a multi-decade investment decision for infrastructure. So we think in some ways, this is the first of many opportunities you could see Range participate in. Again, as you've heard us talk about, given our are 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. So we think there's a lot of reasons for us to be excited about as you can probably tell from my voice this morning. So what's out there that's in addition to this? I mean I think the deal that we signed, though it's difficult for us to share the confidential terms of that arrangement today just given some ask we have from the counterparties associated with it. This is also something that's scalable. So we see there's additional conversations around how we could participate in the scalability of not only this particular infrastructure but also what builds out in the region. And then, of course, you've got closer to home the Fort Cherry project, which we're continuing to see what I would say, 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. So 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 building direct -- or seeing someone build directly behind the meter right in the heart of the field where we produce our NGLs and our natural gas. And 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. And so 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 us significant backstop to those future needs.

And the next question is from John Annis of Texas Capital.

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, but 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?

Yes. 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. And 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. And then I think when you think about the other drivers, clearly, 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. And 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 it's actually taking on market share out of the basin. So think about it as being growth for Range, but not necessarily growth for Appalachia. And 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. So 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 earnings calls. We've got a lot of flexibility built into the program where we could pull down capital and maintain a production profile that's in excess of 2.6 Bcf equivalent per day in '28 and beyond, with something that's in the neighborhood of sub $600 million in CapEx or think about it differently, less than $0.60 per Mcfe. Or we can continue to have a thoughtful wage of growth, depending upon future demand and deals that are worked on, on our end, 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. So 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? And does the current guidance already embed any early benefit from the mid 2026 takeaway additions? Or is that a '27 and beyond story?

Yes, 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. So it's what the market indicated levels are at the myriad of sales points we have across the U.S. So that also baked it 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 to 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. So 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. And then 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 a month for about 90% of our production volumes. So that has proven to be a very successful way of capturing strong prices 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, but 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 increased natural gas sales or ratchet up the extraction levels of ethane prices and net margins are better. So there's a whole host of factors that play in there to that basis differential. But again, what it all comes back to is the business that has been built on top of Range's assets 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 in cash flow per share, not just about growth or production or scale for scale's sake.

The next question is from Doug Leggate of Wolfe Research.

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. So what would cause you not to bring on DUC production if gas prices did indeed prove to be softer for the balance of the year?

Yes. Doug, I think when you look at the balance of the year and the timing at which the infrastructure, let's just say, basically starts to come into service, which would really be end of Q2 type time frame, we kind of feel like the timing really works well when you start to think about the wells that will 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 spending the sales meter through the back half of 2026. So we feel like the timing is set up complementary to improving pricing as you start to get into the end of injection season, which internally, 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 to 3.7 Tcf. So -- in the ground. So 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. But 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 signal. So 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. So we think we've got the right playbook in place for now, but we always leave some flexibility that we can also take some of those TILs, push them deeper into the year if the signals warrant. But when you look at where we are from a commodity price standpoint, how we risk 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. So 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 it. I mean, it's -- in terms of selling into the strength of the market. I was just trying to understand the physics of it. 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 you're breakeven is as low as it is. And 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 midweek just because that's the way the industry works. But 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 Bidweek sets the pace given how good a position your capital structure and so on is in at this point? Why not let more float on the cash market? And I'll leave it there.

Yes, a 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 Bidweek. And I think if you were to ask the question or look back at when we talked about Bidweek and our participation, I think roughly what you've seen us commit to is roughly plus or minus 90% to be committed in the Bidweek process. But what goes into that is really a I'll just say, utilizing internal resources, a multidisciplinary team. It's very talented that involves some of the same expertise that is a part of our hedging committee to also our operations team. And 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. So you do see us toggle that percentage contribution into the Bidweek that's committed. As you think about February, as an example, we kind of walked into that time frame with a much stronger view on the pricing on the front side. So we put 97% of our gas into the Bidweek process to try and capture what we believe was strong pricing and turned out to be excellent pricing. But there are other times when we back off of that to also have more exposure into what we believe is fluctuations in commodity price. And then, of course, lastly, some of our new production may not always go into meeting new well turn-in lines may not always be accounted for in that Bidweek process. So again, we could capture pricing through the balance of that 30-day cycle. So 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 returns.

The next question is from Jacob Roberts of TPH & Co.

Dennis, I appreciate the color on kind of the 2027-plus time frame. I was wondering if you could opine on where you view service costs over that same time period. And really what I'm getting at is their willingness to convert some of that DUC backlog into a more of a deferred till approach, 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?

Yes. Jake, I think when I start to think about the upcoming couple of years, I think the reality is, 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 our liquids contribution at what time of the year, of course. So I think the short answer is, yes. We would absolutely want to factor in what's the best in 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 as 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. And then some are going to be more on a 12-month type structure where you're going to 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 1 to 2 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 multiyear program, which is kind of exciting. So I say all that to say I don't know that I expect service costs to really go down a whole lot more. We're kind of -- it feels like we're reaching a bit of an asymptotic trend on the bottom end here where we're just kind of reaching the close bottom, if you will, and we're bringing out those additional dollars through other operational efficiencies. Water recycling, multiple stages a day, improvements in surface equipment design. So 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 '27 and beyond, is that get invested into another thoughtful wage of growth, depending upon demand that continues to emerge and materialize.

That's super helpful. I did want to circle back to the supply agreement you guys signed, which I agree is very positive to see. I'm curious if the [ $75 million ] to the specific facility is a starting point for this facility. Is there the potential to grow those volumes. And maybe if not, is the specific counterparty someone you could view as someone you pursue additional projects with over the coming years?

Yes, 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. So this was 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. So 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. So yes, it's a great counterparty. It's a really high-quality counterparty on top of it. So 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.

The next question is from Phillip Jungwirth of BMO Capital Markets.

Coming back to the question around growth beyond 2027. Just wondering how you would consider allocating capital across liquids versus dry gas acreage. And 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 taking basin pricing?

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. So I know looking at this year, in prior years, it's tended to fluctuate somewhere between probably 20% to 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 utilize existing infrastructure and incrementally added some nice production to the profile. So we do have, I'll just say, more of that, that we can do if we wanted to flex into a direction of being drier. As far as an infrastructure commitment standpoint, the Harmon Creek processing expansion that goes into service this year really carries a significant amount of momentum through '27 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. So we're bringing 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. And 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. So in the near term, maybe it's more also debottlenecking and bringing out some capacity that can be more efficiently utilized in existing processing plants and gathering. So that's how we're thinking about future growth. And we think the near-term or the time frame it would take to actually see those molecules go into service is -- if that time frame gets truncated, which again gives us more flexibility.

Okay. That's helpful. And 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? And then just given the petchem margins are historical lows, how do 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?

Yes. The NGL macro has been clearly a hot topic as we think about the back half of 2025. So I'm going to attack this from a couple of different angles. But clearly, stock levels have been elevated through 2025, both on the propane and also on the ethane side. And I think each has a different story to tell. But in some ways, they've got a similar story. And the different part of the story is for propane, you had weak demand last year. And of course, there was an increased level of production that was a little stickier, I think, through associated gas contribution, than maybe was somewhat anticipated. And then on top of it, you did have -- on top of the demand being down a little bit in 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 '25. 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, 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 2 million barrels per day type level on the propane side as an example. So as we think about rolling the take 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. And then on top of it, you've got -- I'll just use INEOS and SINOPE, 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. So 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 '24. But 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. So 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.

The next question is from Kevin MacCurdy of Pickering Energy Partners.

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 pretty materially lower than it was a year ago.

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 not to 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 risk 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. So 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 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. So we felt like it allowed us to take on market share instead of thinking about growing for growth sake. That's not a part of the equation for us as we go forward. We have to have a home for those molecules. And so 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. And we also felt like those -- that pipe capacity got us to end markets that would see growing demand in the future. So 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. And 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 can consider more in-basin or regional that allows us to think about that next wage of growth, but it also has to materialize. So 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, '28 and beyond, it will be based upon a home for that production in the in-basin region demand it 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. If we saw first quarter gas prices strong in the Northeast relative to Henry Hub. Can you kind of square why the guidance is the same year-over-year? And give us any comments on how realizations will look throughout the year?

Yes. I think as I started a 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 point. And as we think about how 2026 has begun, we're off to a great start. I think it's important to note that 90-plus percent we take into first month capturing extremely high value. So 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. So I'll just leave it at that. The guide is -- Mark 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.

The next question is from Michael Scialla with Stephens.

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, Mike. I think as we evaluate what the current trading levels of the 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 proved reserves, which is less than a 5-year development plan, we see tremendous value in buying back those shares. So 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 done a formula quite intentionally. We think if you're formulaic and programmatic, you can end up with just a pro-cyclical and by high type program. So we think the flexibility of being opportunistic generates a much better return in buying when you see pullbacks and just lower points, lower entry points in the stock price. That is to say we still see tremendous value and where the stock is trading today. And I think you can look at our track record over the last number of years and the percentage of cash flow that we have deployed in returns of capital as compelling. Again, we're not going to provide a framework for perspective, we've been in the 20% to 30% range the last couple of years. This year approached 50% of free cash flow in returns. So as the best 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.

Yes, 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. I wanted to see what you're assuming for op cost. 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. And as Dennis said, we are approaching the lower limits in many situations on how far you can push costs down. So our focus, of course, is on ringing every penny out of the cost structure that we can contractually and strategically. But for purposes of modeling here, it's essentially flat.

Is there any efficiency upside that could be? I know you talked about water infrastructure and some other places where you could save on op cost going forward?

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. And every year, we are fortunate with a strong and safe execution by the team and continuously surprised by what the range team can do. So I would certainly think that there's a little bit more there, the team can ring out.

And 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.

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 Bidweek. But 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 because I'm sure volatility is here to stay in the gas markets, and just any perspectives on how your marketing can perform during that period of time.

Yes, I think the -- first of all, thanks for joining us, Neil. When I think about that, we are -- sorry, Bidweek and also the operating plan we were able to really lean into the pricing of that $7 type level, which was really significant when you think about the cash flow that gets thrown after that kind of cycle. And 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 driven by other factors. So 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 sub-0 temperatures. And at any 1 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. So 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 the 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 firm that was really important. And 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 generating power for their homes these days. So 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 or Bidweek or leaving more in the daily to try and capture what we think is more of upside opportunity through the balance of that upcoming month. But yes, we'd expect more volatility going forward and 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 a month and perhaps company history.

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 in our next call. Thanks, everyone.